Semco Energy (SEN) 10-K 2005 FY Annual report

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

(Mark One)
þ	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the Fiscal Year Ended December 31, 2005
o	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the transition period from           to

Commission File Number 001-15565

SEMCO Energy, Inc.

(Exact name of registrant as specified in its charter)

Michigan	38-2144267
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)
1411 Third Street, Suite A, Port Huron, Michigan	48060
(Address of principal executive offices)	(Zip Code)

(Registrant’s telephone number, including area code) 810-987-2200

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

Title of Each Class	Name of Each Exchange on Which Registered
Common Stock, $1 Par Value	New York Stock Exchange

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

None

     Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.     Yes o          No þ

      Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.     Yes o          No þ

      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 þ          No o

      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 amendment to this Form 10-K.     o

      Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer o          Accelerated filer þ          Non-accelerated filer o

      Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).     Yes o          No þ

      The aggregate market value of the Registrant’s Common Stock held by non-affiliates as of June 30, 2005, was $162,666,818 based on 27,156,397 shares held by non-affiliates and the closing price of $5.99 on that day (New York Stock Exchange).

      Number of outstanding shares of the Registrant’s Common Stock as of February 28, 2006: 33,726,152

DOCUMENTS INCORPORATED BY REFERENCE:

      Portions of Registrant’s definitive Proxy Statement (filed pursuant to Regulation 14A) with respect to Registrant’s 2006 Annual Meeting of Common Shareholders are incorporated by reference in Part III of this Form 10-K.

TABLE OF CONTENTS

		Page
		Number
Information About Forward-Looking Statements			2
PART I
Item 1.	Business		3
Item 1A.	Risk Factors		11
Item 1B.	Unresolved Staff Comments		21
Item 2.	Properties		21
Item 3.	Legal Proceedings		22
Item 4.	Submission of Matters to a Vote of Security Holders		23
PART II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities		23
Item 6.	Selected Financial Data		25
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operation		26
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk		48
Item 8.	Financial Statements and Supplementary Data		48
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		95
Item 9A.	Controls and Procedures		95
Item 9B.	Other Information		96
PART III
Item 10.	Directors and Executive Officers of the Registrant		97
Item 11.	Executive Compensation		98
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		98
Item 13.	Certain Relationships and Related Transactions		98
Item 14.	Principal Accountant Fees and Services		98
PART IV
Item 15.	Exhibits and Financial Statement Schedules		99
Signatures			105
First Amended and Restated Deferred Compensation and Stock Purchase Plan for Non-Employee Directors
2006 Target Bonuses under the Company's Short-Term Incentive Plan
Base Salaries for Named Executive Officers
First Amendment to Second Amended and Restated Credit Agreement
Letter Agreement between SEMCO Energy, Inc. and LaSalle Bank Midwest National Association
Gas Sales Agreement between Union Oil Company of California and Alaska Pipeline Company
Addendum No. 1, effective as of 11/15/01 to Gas Sales Agreement
Gas Sales Agreement between Anadarko petroleum Corporation, Phillips Alaska, and Alaska Pipeline Company
Assignment Approval, (dated as of December 26, 2002)
Assignment Approval, (dated as of January 13, 2003)
Gas Purchase Contract between Shell Oil Company and Alaska Pipeline Company
Letter Agreement No. 1 dated May 24, 1983
Letter Agreement between Shell Western E&P Inc. and Alaska Pipeline Company
Partial Assignment of the Gas Purchase Contract, effective 10/01/89
Agreement between Alaska Pipeline Company and Shell Western E&P Inc.
Agreement between Alaska Pipeline Company and ARCO Alaska, Inc. dated 11/15/91
Partial Assignment of the Gas Purchase Contract, effective 01/01/93
Assignment and Conveyance of the retained interest in the Gas Purchase Contract, effective 09/01/96
Partial Assignment of the Gas Purchase Contract, effective 12/27/96
Partial Assignment of Gas Purchase Contract, effective 01/07/97
Ratio of Earnings to Fixed Charges
Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividends
Subsidiaries of the Registrant
Consent of Independent Registered Public Accounting Firm
CEO Certification Pursuant to Section 302
CFO Certification Pursuant to Section 302
CEO and CFO Certification Pursuant to 18 U.S.C. Section 1350

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Information About Forward-Looking Statements

      This annual report on Form 10-K contains forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995 that are based on current expectations, estimates and projections of the registrant, SEMCO Energy, Inc. (the “Company”). Statements that are not historical facts, including statements about the Company’s outlook, beliefs, plans, goals, and expectations, are forward-looking statements. In addition, forward-looking statements generally can be identified by the use of forward-looking terminology such as “may,” “will,” “expect,” “intend,” “estimate,” “anticipate,” “believe,” or “continue” or the negatives of these terms or variations of them or similar terminology. These statements are subject to potential risks and uncertainties and, therefore, actual results may differ materially from the expectations described in these statements. Although the Company believes that the expectations reflected in these forward-looking statements are reasonable, the Company cannot provide any assurance that these expectations will prove to be correct. Important factors that could cause actual results to differ materially from the Company’s expectations are described in the Risk Factors section in Item 1A of this Form 10-K and include:

•  the effects of weather and other natural phenomena (including the effects of these phenomena on customer consumption);

•  the economic climate and growth in the geographical areas where the Company does business;

•  the capital intensive nature of the Company’s business;

•  the operational risks associated with operating businesses involved in the storage, transportation and distribution of natural gas and propane;

•  competition within the energy industry as well as from alternative forms of energy;

•  the timing and extent of changes in commodity prices for natural gas and propane and the resulting changes in, among other things, the Company’s working capital requirements, customer rates and customer gas consumption;

•  the effects of changes in governmental and regulatory policies, including income taxes, environmental compliance and authorized rates;

•  the adequacy of authorized rates to compensate the Company, on a timely basis, for the costs of doing business, including the cost of capital and cost of gas supply, and the amount of any cost disallowances;

•  the Company’s ability to procure its gas supply on reasonable credit terms;

•  the availability of long-term gas supplies in the Cook Inlet region of Alaska;

•  the amounts and terms of the Company’s debt and its credit ratings;

•  the Company’s ability to remain in compliance with its debt covenants and accomplish its financing objectives in a timely and cost-effective manner;

•  the Company’s ability to maintain an effective system of internal controls;

•  the Company’s ability to execute its strategic plan effectively, including the ability to make acquisitions and investments on reasonable terms and the reasonableness of any conditions imposed on those transactions by governmental and regulatory agencies;

•  the Company’s ability to conclude litigation and other dispute resolution proceedings on reasonable terms;

•  the Company’s ability to utilize its net operating loss carry-forwards for federal income tax purposes; and

•  changes in the performance of certain assets, which could impact the carrying amount of the Company’s existing goodwill.

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      In this Form 10-K, “include”, “includes”, or “including” means include, includes or including without limitation.

PART I

Item 1. Business

SEMCO Energy, Inc.

      The Company is a New York Stock Exchange (“NYSE”)-listed regulated public utility company headquartered in Port Huron, Michigan. It was founded in 1950 as Southeastern Michigan Gas Company (“SMGC”). In 1977, the Company initiated a reorganization, pursuant to which Southeastern Michigan Gas Enterprises, Inc. (“SMGE”) was formed and SMGC became a wholly-owned subsidiary of SMGE. On April 24, 1997, SMGE’s name was changed to SEMCO Energy, Inc. and SMGC’s name was changed to SEMCO Energy Gas Company. On January 1, 2000, SEMCO Energy Gas Company was merged into SEMCO Energy, Inc. References to the “Company” in this document mean SEMCO Energy, Inc., its subsidiaries, divisions or the business segments discussed below as appropriate in the context of the disclosure.

      The Company operates one reportable business segment: Gas Distribution. The Gas Distribution business segment includes the Company’s natural gas distribution operations in Michigan and Alaska. The Company’s other business segments that do not meet the quantitative thresholds to be reportable business segments (“non-separately reportable business segments”) are combined and included with the Company’s corporate division in a category to which the Company refers to as “Corporate and Other.” The Company’s non-separately reportable business segments primarily include Company operations and investments in information technology services, propane distribution, intrastate natural gas pipelines, and a natural gas storage facility. For further information on the Company’s business segments, refer to Note 11 of the Notes to the Consolidated Financial Statements in Item 8 of this Form 10-K.

Gas Distribution Business Segment

      The Company’s Gas Distribution business segment consists of natural gas distribution operations in Michigan and Alaska. The Michigan operation is sometimes referred to as “SEMCO Gas” and the Alaska operation is sometimes referred to as “ENSTAR.” These operations are referred to together as the “Gas Distribution Business.”

      SEMCO Gas is a division of the Company. The ENSTAR operation includes ENSTAR Natural Gas Company, Alaska Pipeline Company (“APC”) and NORSTAR Pipeline Company (“NORSTAR”). ENSTAR Natural Gas Company is a division of the Company. APC is a subsidiary of the Company and NORSTAR is a subsidiary of APC. APC’s transmission system delivers natural gas from producing fields in South Central Alaska to ENSTAR’s Anchorage-area gas distribution system. APC’s only customer is ENSTAR. NORSTAR began operations in 2002 and provides pipeline management and pipeline construction management services to non-affiliated customers in Alaska.

      The Gas Distribution Business purchases, transports, distributes, and sells natural gas to residential, commercial and industrial customers and is the Company’s largest business segment. The Company’s strategy for the existing Michigan and Alaska gas distribution operations is to expand its transmission and distribution system in an economical manner through appropriate system improvements and the attachment of new customers located on or near gas mains within the Company’s existing service territories. The Company will also seek to grow its Gas Distribution Business (including related pipeline and storage operations) by making appropriate acquisitions and investments in Michigan, Alaska and elsewhere.

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      Set forth in the following table is financial and operating information for the Gas Distribution Business:

			Years Ended December 31,
			2005			2004			2003
Gas sales revenues (in thousands)
	Residential		$	385,978		$	315,606		$	290,911
	Commercial and industrial			183,158			147,750			137,025
		Total gas sales revenue	$	569,136		$	463,356		$	427,936
Gas transportation revenue (in thousands)			$	29,142		$	29,071		$	27,737
Cost of gas sold (in thousands)
	Purchased		$	473,157		$	351,288		$	331,821
	Withdrawn from (injected into) storage			(29,297	)		(5,047	)		(22,902	)
		Total cost of gas sold	$	443,860		$	346,241		$	308,919
Volumes of gas sold (MMcf)(a)
	Residential			44,235			44,880			45,324
	Commercial and industrial			20,488			21,285			21,948
		Total volumes of gas sold		64,723			66,165			67,272
Volumes of gas transported (MMcf)				55,709			56,619			51,358
Total volumes delivered				120,432			122,784			118,630
Temperature Statistics(b)
	Degree Days
		Alaska		9,572			9,573			9,384
		Michigan		6,689			6,726			7,063
	Percent colder (warmer) than normal
		Alaska		(5.7	)%		(6.0	)%		(8.0	)%
		Michigan		(0.1	)%		(0.3	)%		4.7	%
Number of customers at year end				409,462			398,225			390,677
Number of customers, annual average
	Residential			363,678			354,261			346,819
	Commercial and industrial			37,639			37,234			37,640
	Transportation			1,638			1,540			1,481
				402,955			393,035			385,940

(a)

MMcf is a quantity of natural gas equal to one million standard cubic feet.

(b)

Degree days are a measure of coldness determined daily as the number of degrees the average temperature during the day in question is below 65 degrees Fahrenheit. Degree days for a particular year are determined by adding the degree days incurred during each day of that year. The Company determines the percent (%) that weather is warmer or colder than normal for a particular year by computing the deviation of actual degree days for that year from the average of degree days during the prior fifteen years and dividing the deviation by such fifteen-year average. Degree days are an indicator of natural gas consumption, since natural gas supplied and delivered by the Company is used by many customers for space heating, and heating consumption is affected by how warm or cold it is.

      All revenue generated by the Gas Distribution Business for the years ended December 31, 2005, 2004, and 2003, is from non-affiliated customers, except for an inconsequential amount, typically less than 0.05% per year. Refer to Note 11 of the Notes to the Consolidated Financial Statements in Item 8 of this Form 10-K, for

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the operating revenues, operating income, assets and other financial information of the Gas Distribution Business for the past three years.

     Rates and Regulation. The Gas Distribution Business is subject to regulation. The Michigan Public Service Commission (“MPSC”) has jurisdiction over the regulatory matters related to the Company’s Michigan customers, except for customers located in the City of Battle Creek and nearby communities. The regulatory matters related to customers located in the City of Battle Creek and nearby communities are currently subject to the jurisdiction of the City Commission of Battle Creek (“CCBC”). Regulatory matters related to customers in Alaska are subject to the jurisdiction of the Regulatory Commission of Alaska (“RCA”). These regulatory bodies have jurisdiction over, among other things, rates, accounting procedures, and standards of service. The approximate number of the Company’s customers located in service areas regulated by each of the three regulatory bodies is as follows: MPSC — 249,000; CCBC — 37,000; and RCA  — 123,000. In October 2005, the Company and CCBC announced that they will petition the MPSC to assume jurisdiction over customers located in the City of Battle Creek and nearby communities (the regulatory jurisdiction currently exercised by the CCBC). The CCBC and the Company will jointly apply for MPSC acceptance of this jurisdictional change and propose that the MPSC accept the current rates charged to customers in the area regulated by the CCBC as the initial rates to be charged to these customers under MPSC jurisdiction until these rates are changed in accordance with the applicable MPSC procedures. The Company and the CCBC plan to file a joint application with the MPSC in 2006 asking for approval of this jurisdictional change.

      For information on regulatory matters including recent regulatory orders, filings and rate cases, refer to Note 2 of the Notes to the Consolidated Financial Statements in Item 8 of this Form 10-K.

     Gas Sales. Gas sales revenue is generated primarily through the sale and delivery of natural gas to residential and commercial customers. These customers use natural gas mainly for space heating. Consequently, weather has a significant impact on sales. As a result of the impact of weather on this business segment, most of the Company’s gas sales revenue is generated in the first and fourth quarters of the calendar year. Revenues from gas sales accounted for 93% of consolidated operating revenues in 2005, 91% of consolidated operating revenues in 2004, and 90% of consolidated operating revenues in 2003.

      In Michigan, the MPSC has approved a program known as the Gas Customer Choice Program that allows gas sales customers to purchase natural gas from third-party suppliers, while allowing the Gas Distribution Business to continue charging existing distribution charges and customer fees plus a gas load balancing fee. As a result, the Company’s earnings are generally not materially affected by customers switching from gas sales service to the Gas Customer Choice Program. The program is available to all gas sales customers in the Company’s service area regulated by the MPSC. There were no customers taking service under the Gas Customer Choice Program at December 31, 2005. If customers elect to participate in the program, revenues associated with such customers would be recorded in transportation revenue rather than gas sales revenue.

      In Alaska, commercial customers also may purchase natural gas from third-party suppliers. ENSTAR charges the same distribution charges and customer fees for gas transportation service to commercial customers as it does for gas sales service. As a result, the Company’s earnings are generally not materially affected by commercial customers switching from gas sales service to gas transportation service. If customers elect to purchase natural gas from a third-party supplier, revenues associated with such customers would be recorded in transportation revenue rather than gas sales revenue. There were approximately 1,300 commercial customers in Alaska receiving commercial transportation service at December 31, 2005.

     Transportation. The Gas Distribution Business provides transportation services to its large-volume commercial and industrial customers. This service offers those customers the option of purchasing natural gas directly from third-party suppliers. The natural gas purchased by customers from third-party suppliers is then transported on the Company’s gas transmission and distribution network to the customers. Unlike gas sales service, the amount the Company charges its transportation service customers does not include the cost of gas because these customers are not purchasing natural gas from the Company. Transportation services are also available to smaller volume customers who participate in the Gas Customer Choice Program in Michigan or

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commercial customers who elect transportation service in Alaska, as described under the caption “Gas Sales,” above.

     Customer Base. At December 31, 2005, the Gas Distribution Business had approximately 409,000 customers, including 286,000 customers in Michigan and 123,000 customers in Alaska. The largest concentration of customers in Michigan, approximately 119,000, is located in southeastern Michigan, just northeast of the metro-Detroit area. The remaining Michigan customers are located in various areas throughout the state, including Albion, Battle Creek, Holland, Houghton, Marquette, Niles, Ontonagon, St. Ignace and Three Rivers. Customers in Alaska are located in and around the Anchorage and Cook Inlet area, including Big Lake, Bird Creek, Butte, Chugiak, Eagle River, Eklutna, Girdwood, Houston, Indian, Kasilof, Kenai, Knik, Nikiski, Palmer, Peters Creek, Portage, Sterling, Soldotna, Wasilla and Whittier. ENSTAR distributes natural gas to the greater Anchorage metropolitan area, and its service area encompasses over 56% of the population of Alaska.

      The Gas Distribution Business’ customer base is diverse and includes residential, commercial and industrial customers. The largest customers in Michigan include food production facilities, paper processing plants, furniture manufacturers and others in a variety of industries. The largest customers in Alaska include power plants, a liquefied natural gas (“LNG”) plant, a refinery and a fertilizer plant. For further discussion on the potential loss of the fertilizer plant as a customer, refer to the caption “Natural Gas Supply” in Item 1 of this Form 10-K. The average number of customers at SEMCO Gas has increased by an average of approximately 1.4% annually during the past three years (1.3% in 2005), and the average number of customers at ENSTAR has increased by an average of approximately 3.3% annually during the past three years (3.4% in 2005). Average annual gas consumption per customer in both Michigan and Alaska generally has been decreasing because, among other things, new homes and appliances are typically more energy efficient than older homes and appliances. In addition, recent increases in natural gas prices appear to have prompted customers to reduce their gas consumption. For additional information on the impact of higher natural gas prices, refer to the caption “The Impact of Higher Natural Gas Prices” in Item 7 of this Form 10-K.

     Competition. Competition in the gas sales market generally arises from alternative energy sources, such as electricity, propane and oil. However, this competition is generally inhibited because of the time, inconvenience and investment necessary for residential and commercial customers to convert to an alternative energy source even as the price of natural gas fluctuates. For residential and commercial gas sales customers, natural gas typically is the most economical energy source for heating.

      Competition in the gas transportation market generally arises from alternative energy sources, such as coal, electricity, oil and steam. Certain large industrial customers may be able to use one or more alternative energy sources or may shift production to facilities outside the Company’s service territories if the price of natural gas and delivery services increases significantly. Natural gas has typically been less expensive than these alternative energy sources. However, over the past three years, natural gas prices have been higher and more volatile, making some of these alternative energy sources less expensive than natural gas. During the last half of 2005 in particular, the price of natural gas increased substantially. During this period, certain of the Company’s large Michigan industrial customers periodically switched to alternative energy sources. To lessen the possibility of such fuel switching by industrial customers, the Company offers flexible contract terms and additional services, such as gas storage and balancing. Partially offsetting the impact of this price sensitivity among certain large industrial customers has been the use of natural gas as an industrial fuel because of environmental regulations and other programs and activities and the resultant pressures on industrial customers to reduce emissions from their plants.

      There is a risk that industrial customers located in close proximity to interstate natural gas pipelines will bypass the Company’s transmission and distribution system by connecting directly to those pipelines. The Company has addressed, and expects to continue to address, any such efforts by offering flexible contract terms and additional services intended to retain these customers on the Company’s system. Gas sales, power plant and commercial transportation customers in ENSTAR’s service territory are currently precluded from bypassing ENSTAR’s transportation and distribution system due to the limited availability of gas transmission systems and the large distances between producing fields and the locations of current customers.

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     Natural Gas Supply. SEMCO Gas has access to natural gas supplies throughout the United States and Canada via major interstate and intrastate pipelines in and near Michigan. SEMCO Gas has pipeline capacity contracts with ANR Pipeline Company, Great Lakes Gas Transmission Limited Partnership, Northern Natural Gas Company, Panhandle Eastern Pipe Line Company, Trunkline Gas Company, LLC, Michigan Consolidated Gas Company and Consumers Energy Company. The Company also owns underground storage facilities in Michigan with a working capacity of 5.1 billion cubic feet (“Bcf”). In addition, it leases 6.5 Bcf of storage from Eaton Rapids Gas Storage System (“ERGSS”) and 3.5 Bcf from non-affiliates in Michigan. The owned and leased storage capacity equals approximately 37% of the Company’s 2005 annual gas sales volumes in Michigan. SEMCO Gas Storage Company, a subsidiary of the Company, is a 50% owner of the ERGSS.

      SEMCO Gas has negotiated standard terms and conditions for the purchase of natural gas under the North American Energy Standards Board (“NAESB”) form of agreement with a variety of suppliers, including BP Canada Energy Marketing Corp. (“BP”), Charlevoix Energy, Chevron U.S.A., Cinergy Marketing, Coral Energy, Cornerstone Energy, Husky Oil, Mid-American Energy, Nexen Marketing, OGE Energy, ONEOK Energy, ConocoPhillips, Cargill Inc., and Tenaska Marketing. SEMCO Gas purchases natural gas under one or more of these agreements for resale to customers in Michigan, typically in accordance with a gas supply procurement plan approved by the MPSC for customers in areas regulated by the MPSC.

      SEMCO Gas has an asset management agreement with BP covering the period of April 1, 2005, through March 31, 2008. Under the agreement with BP, BP provides transportation and storage asset management services for the Company for customers in its service area regulated by the MPSC (“MPSC-regulated customers”) and customers in its service area regulated by the CCBC (“CCBC-regulated customers”).

      The Company’s MPSC-regulated customers have paid for natural gas commodity costs through a gas cost recovery (“GCR”) pricing mechanism since April 1, 2002. The MPSC typically reviews and approves a gas supply procurement plan submitted annually by the Company, covering purchases from April 1 of one year to March 31 of the next year. These purchases include both gas supplies for use by customers, commitments to future gas deliveries, and storage injections and withdrawals. The Company’s MPSC-approved GCR gas purchase plans require the Company to solicit bids for all supplies with contract term lengths longer than three days, which, during 2005, constituted approximately 100% of the Company’s sales to MPSC customers. Supplies with contract term lengths of three days or less may be purchased without bidding.

      The Company’s CCBC-regulated customers have paid for natural gas commodity costs through a GCR pricing mechanism since April 1, 2005. The CCBC periodically audits the Company’s gas supply procurement plan, which is substantially similar to the one used to procure gas supplies for MPSC-regulated customers.

      For MPSC- and CCBC-regulated customers, all gas supplies purchased during each GCR period are based on a portfolio of short-term fixed priced and short-term index priced supply agreements. For information about how the GCR pricing mechanism and related MPSC reviews impact the cost of gas, refer to the “Cost of Gas, Gas Charges Recoverable from Customers, and Amounts Payable to Customers” section within Note 1 of the Notes to the Consolidated Financial Statements in Item 8 of this Form 10-K.

      ENSTAR has access to natural gas supplies in close proximity to its Alaska service territory. ENSTAR’s system, including the APC pipeline system, is not linked to major interstate and intrastate pipelines and natural gas supplies in other states or Canada. As a result, ENSTAR procures natural gas supplies under long-term, RCA-approved contracts, from producers in and near the Cook Inlet area.

      ENSTAR has a gas purchase contract with Marathon Oil Company (“Marathon”) that has been approved by the RCA (the “1988 Marathon Contract”). It is a requirements contract with no specified daily deliverability or annual take-or-pay quantities. Marathon is required to deliver up to 13 Bcf of gas in 2006. Each year thereafter, Marathon’s maximum delivery obligation decreases by 2 Bcf per year until 2010 when it will be 5 Bcf. The annual delivery obligation remains at 5 Bcf per year until the original commitment of 456 Bcf has been exhausted, which is expected to be in 2018. The contract has a base price and is subject to an annual adjustment based on changes in the price of certain traded oil futures contracts plus reimbursement for severance taxes and other charges.

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      ENSTAR has RCA-approved gas purchase contracts with Anchorage Municipal Light and Power, Chevron U.S.A., Inc. and ConocoPhillips Alaska, Inc. that provide for the delivery of gas through the year 2009 from the Beluga natural gas field (collectively, the “Beluga Contract”). ENSTAR’s obligation to take gas under the Beluga Contract is estimated to be approximately 1.1 Bcf in 2006, declining to approximately 0.6 Bcf in 2009. The pricing mechanism in the Beluga Contract is similar to the Marathon Contract.

      ENSTAR has an RCA-approved gas supply contract with Aurora Gas for natural gas deliveries from the Moquawkie natural gas field (the “Moquawkie Contract”). The Moquawkie Contract provides that Aurora Gas will supply a portion of ENSTAR’s needs through 2014. Aurora is required to deliver up to 1.8 Bcf of natural gas in 2006. This requirement declines annually until the projected final year requirement of 0.2 Bcf in 2014. The total remaining commitment at the end of 2005 was approximately 10 Bcf. The contract has a base price, subject to annual adjustment based upon 50% of the change in certain inflation measures, plus reimbursement for any severance taxes and other charges.

      ENSTAR also has an RCA-approved gas supply contract with Union Oil Company of California (“Unocal”) (the “Unocal Contract”). Natural gas deliveries under this contract began in 2004. The Unocal Contract provides that Unocal will supply all of ENSTAR’s natural gas requirements not met by the 1988 Marathon, Beluga and Moquawkie Contracts, through 2005, and supply all or a portion of ENSTAR’s requirements in years beyond 2005 based upon additional commitments that may be made by Unocal annually in October. In October 2005, Unocal made a commitment to supply all of ENSTAR’s requirements (not met by the 1988 Marathon, Beluga and Moquawkie Contracts) through 2008 and to supply 19 Bcf in 2009 and in 2010. In any year after 2010, Unocal cannot reduce its commitment by more than 3 Bcf per year. Under the terms of the Unocal Contract, Unocal must advise ENSTAR each October of Unocal’s commitments for the next five years. Each commitment of gas is subject to review by an independent petroleum engineer, but Unocal does not guarantee that it has reserves sufficient to meet its obligations. Under specified circumstances, Unocal may reduce or terminate its obligations to deliver gas. Gas supplied under the Unocal Contract is priced annually according to a36-month daily average price of certain traded natural gas futures contracts, subject to a floor price. The Unocal Contract also provides for reimbursement for severance taxes and other charges.

      ENSTAR has entered into an additional gas supply agreement for its Alaska service area with Marathon Oil Company (the “2005 Marathon Contract”). The 2005 Marathon Contract provides for natural gas deliveries to begin in 2009 and run through at least 2017, for a total of approximately 60 Bcf of natural gas. The 2005 Marathon Contract is a requirements-style contract, with annual delivery amounts dependent upon the Company’s annual natural gas demand in its Alaska service area and the deliveries under the Company’s other RCA-approved gas supply contracts. Gas supplied under the 2005 Marathon Contract is priced annually according to a12-month daily average price of certain traded natural gas futures contracts, discounted if the average price exceeds $6.00 per thousand cubic feet (���Mcf”), and subject to indexed floor and ceiling prices. The 2005 Marathon Contract also provides for a $0.25 per Mcf transportation fee and reimbursement for severance taxes and other charges. The 2005 Marathon Contract is subject to the approval of the RCA and was submitted for approval in November 2005.

      The Unocal, 1988 Marathon, Beluga and Moquawkie Contracts collectively provide for all of ENSTAR’s supply requirements through 2008. RCA approval of the 2005 Marathon Contract will extend that timeframe through 2010. If Unocal continues to commit 19 Bcf per year through 2016, then all of ENSTAR’s requirements will be provided for through 2016. After 2016, natural gas will still be available under the Unocal Contract, the 1988 Marathon Contract and the 2005 Marathon Contract in accordance with their terms, but at least a portion of ENSTAR’s requirements is expected to be met by amendments to those contracts or by new contracts.

      Production from the Cook Inlet area natural gas fields is declining, and new discoveries have been modest. As of January 1, 2004, the Cook Inlet area had approximately 2.1 trillion cubic feet (“Tcf”) of total proven natural gas reserves according to the most recently available information contained in the Alaska Department of Natural Resources Division of Oil and Gas 2004 Annual Report. Based on the Department’s reported 2003 net production of 208 Bcf, there was a reserve life at January 1, 2004, of approximately 10 years

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in the Cook Inlet area, although shortages of daily deliverability have occurred, resulting in curtailment of some industrial loads during cold weather periods. There is ongoing exploration for natural gas in the Cook Inlet area by several parties, including producers that have supply contracts with ENSTAR. This exploration is confined to areas in or near producing fields. The United States Geological Survey and Minerals Management Service has estimated that the Cook Inlet area contains approximately 2.3 Tcf of undiscovered natural gas, but there are no assurances that any of this natural gas will be discovered and, if discovered, can be produced economically and secured by ENSTAR on terms and conditions that would be acceptable to the RCA.

      ENSTAR has been active in efforts to extend its supply of Cook Inlet area natural gas and to find other gas sources. Approximately 125 to 140 Bcf of natural gas are exported each year from Cook Inlet in the form of LNG and ammonia-urea fertilizer. The owner of the fertilizer plant has publicly announced that it has experienced difficulty in securing sufficient natural gas supplies at an appropriate price to continue operating in the future. The owner of the plant has said that it has secured sufficient natural gas supplies to operate at a reduced rate through October 2006, but currently does not have sufficient natural gas under contract at an appropriate price to operate after that date. The Company cannot predict whether the fertilizer plant will ultimately close or whether the export license for the LNG plant that expires on March 31, 2009, will be renewed. In the negotiations with potential gas suppliers, ENSTAR is encouraging development of storage to minimize potential deliverability problems and to enhance opportunities for independent producers to develop natural gas fields that might not be economical without storage. In addition, preliminary activity by other energy industry participants is underway to finance, permit and build a natural gas pipeline that would extend from Alaska’s North Slope, through central Alaska and Canada, to the lower 48 states of the United States. Assuming this pipeline is built, the flow of natural gas through it could not be expected to begin before the middle of the next decade, at the earliest. ENSTAR is engaged in an effort to make customers and public officials aware of the importance of the North Slope natural gas pipeline and the need to make North Slope natural gas available in the Cook Inlet area. The Company can provide no assurances, however, with respect to the building of this pipeline, when it will be put in service, or whether natural gas supplies transported by the pipeline would be available to ENSTAR customers and secured by ENSTAR on terms and conditions that would be acceptable to the RCA.

     Environmental Matters. Prior to the construction of major natural gas interstate pipelines, gas for heating and other uses was manufactured from processes involving coal, coke or oil. Residual byproducts of these processes may have caused environmental conditions that require investigation and remediation. The Company owns seven sites in Michigan where such manufactured gas plants were located. Even though the Company never operated manufactured gas facilities at four of the sites, and did so at one site for only a brief period of time, the Company is subject to local, state and federal laws and regulations that require, among other things, the investigation and, if necessary, the remediation of contamination associated with these sites, irrespective of fault, legality of initial activity, or ownership, and which may impose liability for damages to natural resources. The Company has complied with the applicable Michigan Department of Environmental Quality (“MDEQ”) requirements, which require current landowners to mitigate unacceptable risks to human health from the byproducts of manufactured gas plant operations and to notify the MDEQ and adjacent property owners of potential contaminant migration. The Company is currently investigating these sites, and anticipates conducting any necessary additional investigatory and remedial activities as appropriate. The Company has already remediated and closed a site related to one of the manufactured gas plant sites, with the MDEQ’s approval.

      The Company is also attempting to identify other potentially responsible parties to bear some or all of the costs and liabilities associated with the investigatory and remedial activities at several of these sites and also is pursuing recovery of the costs of these activities from insurance carriers. The Company is unable to predict, however, whether and to what extent it will be successful in involving other potentially responsible parties in investigatory or remedial activities, or in bearing some or all of the costs thereof, or in securing insurance recoveries for some or all of the costs associated with these sites.

      The Company also is unable to estimate, at present, the costs that may be incurred in connection with the investigation and remediation of these sites or other potential environmental liabilities relating to these sites.

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In accordance with an MPSC accounting order, environmental investigation and remediation costs associated with certain manufactured gas plant sites are deferred and amortized over ten years. Rate recognition of the related amortization expense does not begin until a review of the related costs in a base rate case.

Corporate and Other

      Corporate and Other includes the Company’s corporate division and non-separately reportable business segments. These non-separately reportable businesses are organized as subsidiaries of SEMCO Energy, Inc. and generally complement the Company’s Gas Distribution Business. Refer to Note 11 of the Notes to the Consolidated Financial Statements in Item 8 of this Form 10-K, for operating revenues, operating income, assets and other financial information for Corporate and Other for the past three years.

      The Company has reorganized its information technology (“IT”) business operation to focus primarily on the Company’s IT needs, resulting in declining IT revenues from non-affiliated customers. The focus on the Company’s IT needs includes the expected implementation, in 2006, of a new Customer Information System and related system changes and upgrades. The Company expects to continue to provide IT services to certain non-affiliated customers where it believes that it can do so profitably. As part of the restructuring of its IT business operation, the Company exited the residential internet service provider (“ISP”) portion of its ISP business.

      The Company owns a propane distribution business known as “Hotflame.” Hotflame typically supplies approximately 4 million gallons of propane annually to retail customers in Michigan’s Upper Peninsula and northeast Wisconsin. Because propane is used principally for heating, most of the operating income for the propane business is generated in the first and fourth quarters of the calendar year. Propane is transported easily in pressurized containers and is generally used in rural areas where natural gas pipelines and distribution systems do not exist or are not economical to build. The Company has access to a variety of propane suppliers, including NGL Supply, Inc., Mark West, and Amerigas. The propane operation competes with other energy sources, such as natural gas, fuel oil, electricity and other regional and national propane providers, generally based on price and service.

      The Company’s pipelines and storage business consist of three pipelines and a gas storage facility, all of which are located in Michigan. The Company has a partial ownership interest in one of the pipelines and an equity interest in the gas storage facility. Refer to Item 2 of this Form 10-K for additional information on each pipeline and the storage facility.

      The Company’s corporate division is a cost center rather than a business segment. The operating expenses of the corporate division that relate to the ongoing operations of the Company’s business segments are allocated to those business segments using a formula that is accepted by the regulatory bodies that have jurisdiction over the Gas Distribution Business. Examples of functions performed by the corporate division on behalf of the Company’s business segments include administration, human resources, legal, treasury, finance and accounting. Any corporate expenses that do not relate to the ongoing operations of the Company’s business segments or are not allocable to them under various regulatory rules are not allocated to these segments but remain on the books of the corporate division.

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Miscellaneous Information

      The Company had approximately 566 full-time employees at December 31, 2005, compared to 576 full-time employees at December 31, 2004. Approximately 277 of the employees at December 31, 2005, were represented by unions for purposes of collective bargaining compared to 269 employees at December 31, 2004. The current collective bargaining agreements with various union-represented employees are identified below:

			No. of
		Division/	Employees
Collective Bargaining Agreement With		Business Unit	Covered		Expiration Date
Local 328 Teamsters		Hotflame		9	February 28, 2007
Local 3135 Steelworkers		MPSC		20	April 19, 2007
Local 16201 Steelworkers		MPSC		44	June 28, 2007
Local 473 Utility Workers		MPSC		39	December 7, 2007
Local 445 Utility Workers		Battle Creek		38	September 11, 2008
Local 367 Plumbers and Pipefitters Operating Unit		ENSTAR		88	April 1, 2009
Local 367 Plumbers and Pipefitters Clerical Unit		ENSTAR		39	April 1, 2009
	Total			277

      The Company maintains a website on the Internet at address http://www.semcoenergy.com. The Company makes available free of charge, on or through its website, its proxy statements, annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and any amendments to those reports as soon as reasonably practicable after such material is electronically filed with the Securities and Exchange Commission (“SEC”). This reference to the Company’s Internet address shall not, under any circumstances, be deemed to incorporate the information available at such Internet address into this Form 10-K or other SEC filings. The information available at the Company’s Internet address is not part of this Form 10-K or any other report filed by the Company with the SEC. The public may read and copy any documents the Company files at the SEC’s Public Reference Room at 100 F Street, N.E. Washington, D.C. 20549. The public may obtain information on the operation of the Public Reference Room by calling the SEC at1-800-SEC-0330. The Company’s SEC filings can also be obtained on the SEC’s website on the Internet at address http://www.sec.gov.

Item 1A.      Risk Factors

      Investing in the Company involves a number of risks. Investors should carefully consider all of the information contained in this annual report on Form 10-K, as well as the other filings of the Company with the SEC, including the risk factors set forth below, before making an investment in the Company. Described below are some of the risk factors currently known to the Company which make an investment in the Company speculative or risky. The Company may encounter risks in addition to those described below. Investors may lose all or part of their investment in the Company.

Risks Relating to the Company’s Operations

The Company’s natural gas distribution business is subject to rate regulation, and certain actions of these regulatory bodies may reduce the Company’s revenues, earnings and cash flow.

      The Company is currently regulated by the MPSC and the CCBC in Michigan and the RCA in Alaska. These regulatory bodies have jurisdiction over, among other things, rates, accounting procedures and standards of service. With regard to regulation by the MPSC and the CCBC, in March 2005 and February 2005, respectively, the Company entered into settlements which, upon approval, authorized rate increases for customers in these jurisdictions. With certain exceptions, the Company has agreed not to request a further base rate increase with the CCBC to be effective before April 1, 2008, but the Company is not restricted in requesting that the MPSC authorize further base rate increases. In addition, on October 5, 2005, the Company and the CCBC announced that they will ask the MPSC to assume jurisdiction over the CCBC

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service area. The Company and the CCBC plan to file a joint application with the MPSC in 2006 asking for approval of this jurisdictional change. The Company cannot predict when the MPSC will assume jurisdiction, if at all. The Company believes that this proposed change will not have a material impact on the natural gas rates it charges in its CCBC service area, but the Company cannot assure that this change in jurisdiction will not affect the rates it charges or other aspects of the terms and conditions of service. With regard to regulation by the RCA, in June 2005, the RCA issued an order that, among other things, requires ENSTAR and APC to file a depreciation study of their Alaska utility plant by June 1, 2007 (as of December 31, 2006) and a revenue requirement andcost-of-service study (including rate design data) with the RCA by June 6, 2008 (using a test year ended December 31, 2007).

      Approximately 99% of the Company’s 2005 consolidated operating revenues were generated by its regulated Gas Distribution Business. While the Company currently has settlements with the MPSC and the CCBC setting rates in those jurisdictions, there is no guarantee that the Company would prevail in seeking rate increases in future rate cases. The Company also has no guarantee that it will be successful in its rate case to be filed with the RCA after December 31, 2007. The possibility of a rate decrease, the failure to grant any requested rate increase, cost disallowances, the precise timing of any rate increase, decrease or any other action by the Company’s regulators, may reduce the Company’s revenues, earnings and cash flow.

The increased cost of purchasing natural gas during periods in which natural gas prices are rising significantly could adversely impact the Company’s liquidity and earnings.

      One component of the regulation of the Company’s rates is the ability to recover the cost of purchasing natural gas. In general, the costs of natural gas purchased for customers are recovered on a dollar-for-dollar basis (in the absence of disallowances), without a profit component. The recovery of these gas costs is accomplished through regulatory body-approved GCR pricing mechanisms whereby customer rates are periodically adjusted for increases and decreases in the cost of gas purchased by the Company for sale to its customers. Under the GCR pricing mechanisms, the gas commodity charge portion of customers’ gas rates (which is also referred to as the “GCR rate”) in Alaska and the Company’s Michigan service area regulated by the MPSC is generally adjusted annually to reflect the estimated cost of gas purchased for the upcoming12-month GCR period. The GCR rate may be adjusted more frequently than annually if it is determined that there are significant variances from the estimates used in the annual determination. The GCR rate for the Company’s Battle Creek service territory can be adjusted monthly.

      The price of natural gas has increased substantially since mid-2005 and natural gas purchases for customers in the Company’s Michigan gas service areas since then have, and future purchases are expected to, cost significantly more than in the past. The price of natural gas purchased under long-term contracts for the Company’s Alaska service area customers has also increased, and future purchases are expected to cost the Company more than in the past, as the indexes used to determine the prices the Company pays for natural gas under these contracts reflect market price increases.

      These increases in natural gas prices and corresponding increases in GCR rates may contribute, in varying amounts, depending on the way in which these costs are recovered in customer rates in each jurisdiction in which the Company does business, to: (i) increased costs associated with lost and unaccounted-for gas; (ii) higher customer bad debt expense for uncollectible accounts; (iii) higher working capital requirements; and (iv) reduced sales volumes and related margins due to lower customer consumption.

Volatility in the price of natural gas could result in large industrial customers switching to alternative energy sources and reduced revenues, earnings and cash flow.

      The market price of alternative energy sources such as coal, electricity, oil and steam is the primary competitive factor affecting the demand for the Company’s gas transportation services. Certain large industrial customers have, or may acquire, the capacity to be able to use one or more alternative energy sources or shift production to facilities outside the Company’s service area if the price of natural gas and delivery services increases significantly. Natural gas has typically been less expensive than these alternative energy sources. However, generally over the past three years and recently in a more significant way, natural gas prices have

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been higher and more volatile, making some of these alternative energy sources more economical or, for other reasons, more attractive than natural gas. During this period, certain of the Company’s large Michigan industrial customers have periodically switched to alternative energy sources.

      To lessen the possibility of fuel switching by industrial customers, the Company offers flexible contract terms and additional services, such as gas storage and balancing. Partially offsetting the impact of this price sensitivity among certain large industrial customers has been the use of natural gas to reduce emissions from their plants. The Company cannot predict the future stability of natural gas prices; nor can the Company make any assurances that the impact of environmental legislation or any special services the Company offers will outweigh the negative effects of natural gas price increases and volatility. Should these customers convert their requirements to another form of energy, the Company’s revenues, earnings and cash flow would be adversely affected.

The Company’s liquidity and earnings could be adversely affected by the MPSC’s disallowance of costs after retrospective reviews of the Company’s gas procurement practices.

      In the Company’s gas distribution area regulated by the MPSC, the Company’s gas procurement practices are subject to an annual retrospective MPSC review. If costs are disallowed in this review process, such costs would be expensed in the cost of gas but would not be recovered by the Company in rates. The ability of the MPSC to annually retrospectively review the Company’s gas procurement practices creates the potential for the disallowance of the Company’s recovery, through its GCR rates, of some of its costs of purchasing gas. Such disallowances could affect the Company’s liquidity and earnings.

The Company’s earnings and cash flow are sensitive to decreases in customer consumption resulting from warmer than normal temperatures and customer conservation.

      The Company’s gas sales revenue is generated primarily through the sale and delivery of natural gas to residential and commercial customers who use natural gas mainly for space heating. Consequently, weather has a significant impact on sales and revenues. Given the impact of weather on the Company’s Gas Distribution Business, this segment is a seasonal business. Most of the Company’s gas sales revenue is generated in the first and fourth quarters of the calendar year and the Company typically experiences losses in the non-heating season, which occurs in the second and third fiscal quarters of the year. In addition, conservation has continued to reduce demand for natural gas from the Company’s customers.

      Warmer than normal weather and conservation over the last several years have adversely affected the earnings and cash flow of the Company’s Gas Distribution Business, which has accounted for more than 98% of consolidated operating revenues for the last three fiscal years. In the Michigan service area, the temperature was approximately 0.1% and 0.3% warmer than normal during 2005 and 2004, respectively, and approximately 4.7% colder than normal during 2003. The temperature was approximately 5.7%, 6.0% and 8.0% warmer than normal in the Alaska service area during 2005, 2004 and 2003, respectively. In addition, the average annual natural gas consumption of customers has been decreasing because, among other things, new homes and appliances are typically more energy efficient than older homes and appliances, and customers appear to be continuing a pattern of conserving energy by utilizing energy efficient heating systems, insulation, alternative energy sources, and other energy savings devices and techniques. A mild winter, as well as continued or increased conservation, in any of the Company’s service areas can have a significant adverse impact on demand for natural gas and, consequently, earnings and cash flow.

The Company’s earnings are substantially dependent on its current customers maintaining a certain level of consumption as well as customer growth.

      As discussed above, many of the Company’s customers appear to be continuing a pattern of conserving energy by utilizing energy efficient heating systems, insulation, alternative energy sources, and other energy savings devices and techniques. During the past several years, average annual gas consumption has been decreasing. In addition, increases in natural gas prices appear to have increased conservation efforts by customers. The Company expects this conservation trend to continue as an era of higher and more volatile

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natural gas prices influences customer consumption. The Company’s rates are currently based on certain levels of consumption by its customers. Continued and significant declines in consumption by the Company’s current customers, without an adjustment to its rates or rate design, may negatively impact the Company’s earnings.

      In addition, the Company’s earnings growth is substantially dependent on customer growth. The average number of gas sales customers in Michigan and Alaska combined (excluding customers acquired in the acquisition of Peninsular Gas Company (“Peninsular Gas”)) has increased by an average of 2.0% annually during the past three years. If the Company is unable to achieve sufficient customer growth within its existing service territories or add additional customers by expanding service territories, the Company’s earnings growth may be negatively impacted.

The Company’s customers may be able to acquire natural gas without using the Company’s distribution system, which would reduce revenues and earnings.

      There is potential risk that industrial customers and electric generating plants located in close proximity to interstate natural gas pipelines will bypass the Company’s distribution system and connect directly to such pipelines, which would reduce the Company’s revenues and earnings. From time to time, customers raise the issue of bypass and the Company attempts to address their concerns. The Company can make no assurances that its customers will not bypass the Company’s distribution system or that the Company could successfully retain such customers.

Declining production from the Cook Inlet gas fields may result in potential deliverability problems in ENSTAR’s service area.

      ENSTAR’s gas distribution system, including the APC pipeline system, is not linked to major interstate and intrastate pipelines or natural gas supplies in the United States or Canada. As a result, ENSTAR procures natural gas supplies under long-term RCA-approved contracts from producers in and near the Cook Inlet area. Production from the Cook Inlet area gas fields is declining and new discoveries have been modest. As of January 1, 2004, the Cook Inlet area had approximately 2.1 Tcf of total proven natural gas reserves according to the most recently available information contained in the Alaska Department of Natural Resources Division of Oil and Gas 2004 Annual Report. Based on the Department’s reported 2003 net production of 208 Bcf, there was a reserve life at January 1, 2004, of approximately 10 years in the Cook Inlet area, although shortages of daily deliverability have occurred resulting in curtailment of some industrial loads during cold weather periods. There is ongoing exploration for natural gas in the Cook Inlet area by several parties, including producers that have supply contracts with ENSTAR. The United States Geological Survey and Minerals Management Service has estimated that the Cook Inlet area contains another approximately 2.3 Tcf of undiscovered natural gas, but there are no assurances that any of this natural gas will be discovered and, if discovered, can be produced economically and secured by ENSTAR on terms and conditions that would be acceptable to the RCA.

      ENSTAR has been active in efforts to extend its supply of Cook Inlet gas and to find other gas sources. In addition, preliminary activity by other energy industry participants is underway to finance, permit and build a natural gas pipeline that would extend from Alaska’s North Slope, through Alaska and Canada, to the lower 48 states of the United States. Assuming this pipeline is built, the flow of natural gas through it could not be expected to begin before the middle of the next decade, at the earliest. ENSTAR is engaged in an effort to make customers and public officials aware of the importance of the North Slope natural gas pipeline and the need to make North Slope natural gas available in the Cook Inlet area. The Company can provide no assurances, however, with respect to the building of this pipeline, when it will be put in service, or whether natural gas supplies transported by the pipeline would be available to ENSTAR customers and secured by ENSTAR on terms and conditions that would be acceptable to the RCA.

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Changes in the regulatory environment and events in the energy markets that are beyond the Company’s control may reduce the Company’s earnings and limit its access to capital markets.

      The Company’s Gas Distribution Business is subject to regulation by various federal, state and local regulators as well as the actions of federal, state and local legislators. As a result of the energy crisis in California during 2000 and 2001, the recent volatility of natural gas prices in North America, the bankruptcy filings by certain energy companies, investigations by governmental authorities into energy trading activities, the collapse in market values of energy companies and the downgrading by rating agencies of a large number of companies in the energy sector, companies in regulated and unregulated energy businesses have generally been under an increased amount of scrutiny by federal, state and local regulators, participants in the capital markets and debt rating agencies. In addition, the Financial Accounting Standards Board, or FASB, or the SEC could enact new accounting standards that could impact the way the Company is required to record revenues, expenses, assets and liabilities. The Company cannot predict or control what effect these types of events, or future actions of regulatory agencies in response to such events, may have on its earnings or access to the capital markets.

The Company may be required to recognize additional impairment charges which would reduce its earnings.

      Pursuant to generally accepted accounting principles, the Company is required to perform impairment tests on its goodwill balance annually or at any time when events occur that could impact the value of its business segments.

      The 2005 annual goodwill impairment test for the Company’s propane business was performed during the third quarter of 2005 and showed that there was no impairment of goodwill. The 2005 annual impairment test for the Company’s Gas Distribution Business was performed during the fourth quarter of 2005 and showed that there was no impairment of goodwill. There were no adverse changes in the carrying amount of goodwill for 2005.

      During the fourth quarter of 2004, it was determined that all of the goodwill associated with the Company’s IT services business ($0.2 million) was impaired. The $0.2 million before-tax charge for impairment of goodwill is reflected in the Company’s Consolidated Statements of Operations for the year ended December 31, 2004, in operating expenses. During the third quarter of 2003, it was determined that all of the goodwill associated with the Company’s construction services business ($17.6 million) was impaired. The $17.6 million before-tax charge for impairment of goodwill is reflected in the Company’s Consolidated Statements of Operations for the year ended December 31, 2003, as part of the loss from the discontinued construction services business.

      The Company’s determination of whether an impairment has occurred is based on an estimate of discounted cash flows attributable to reporting units that have goodwill. The Company must make long-term forecasts of future revenues, expenses and capital expenditures related to the reporting unit in order to make the estimate of discounted cash flows. These forecasts require assumptions about future demand, future market conditions, regulatory developments and other factors. Significant and unanticipated changes to these assumptions could require a provision for impairment in a future period that could substantially reduce the Company’s earnings in a period of such change, but not have any impact on its cash flow.

The Company’s ability to use net operating loss carry-forwards may be impaired.

      As of December 31, 2005, the Company had available approximately $96 million of net operating losses, or NOLs, with which to offset federal income taxes with respect to the Company’s future taxable income. In 2004, the Company underwent an “ownership change” for purposes of Section 382 of the Internal Revenue Code of 1986, as amended. In general, an ownership change occurs whenever there is a more than 50% change in the ownership of the stock of a corporation, taking into account all cumulative changes in ownership over the preceding three years. As a result of the ownership change, the Company’s ability to use approximately $86 million of its total NOLs in the future is limited. However, the Company believes that, based on the size

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of the limitation and projections of future taxable income, the Company should be able to utilize all of the NOLs before they expire.

      The issuance of additional shares in the Company’s capital stock could ultimately trigger another ownership change that could further limit the Company’s ability to use such NOLs. While the Company’s March 2005 issuance of 5% Series B Convertible Cumulative Preferred Stock (“Preferred Stock”) and the August 2005 Common Stock offering did not trigger such an ownership change, those offerings when coupled with future capital stock offerings and changes in the ownership of the Company’s capital stock (some of which will be beyond the Company’s control) will probably lead to a future ownership change. Any such future ownership change could result in the imposition of lower limits on the Company’s utilization of the NOLs to offset future taxable income as well as the Company’s ability to use certain losses and tax credits. The magnitude of such limitations and their effect on the Company is difficult to assess and will depend in part on the value of the Company at the time of any such ownership change and prevailing interest rates at that time.

The Company’s operations and business are subject to environmental laws and regulations that may increase the Company’s cost of operations, impact or limit the Company’s business plans or expose the Company to environmental liabilities.

      The Company’s operations and business are subject to environmental laws and regulations that relate to the environment and health and safety, including those that impose liability for the costs of investigation and remediation, and for damage to natural resources from, past spills, waste disposal on- and off-site and other releases of hazardous materials or regulated substances. In particular, under applicable environmental requirements, the Company may be responsible for the investigation and remediation of environmental conditions at currently owned or leased sites, as well as formerly owned, leased, operated or used sites. The Company may be subject to associated liabilities, including liabilities resulting from lawsuits brought by private litigants, related to the operations of the Company’s facilities or the land on which such facilities are located, regardless or whether the Company leases or owns the facility, and regardless of whether such environmental conditions were created by the Company or by a prior owner or tenant, or by a third-party or a neighboring facility whose operations may have affected the Company’s facility or land.

      Given the nature of the past operations conducted by the Company and others at the Company’s properties, there can be no assurance that all potential instances of soil or groundwater contamination have been identified, even for those properties where environmental site assessments or other investigations have been conducted. Changes in existing laws or policies or their enforcement, future spills or accidents or the discovery of currently unknown contamination may give rise to environmental liabilities which may be material. Based upon the information presently available to the Company, the Company expects to incur costs associated with investigatory and remedial actions at seven of its Michigan sites that formerly housed manufactured gas plant operations. Because the extent of the soil and groundwater contamination at these sites has not been fully delineated and the scope of the Company’s liability (along with other responsible parties, if any) has not been determined, it is difficult for the Company to estimate its liability at this time. However, it is possible that the Company’s share of such liability could be material. To the extent not fully recoverable from customers through regulatory proceedings or from insurance, these costs would reduce the Company’s earnings and results of operations.

      Compliance with the requirements and terms and conditions of the environmental licenses, permits and other approvals that are required for the operation of the Company’s business may cause the Company to incur substantial capital costs and operating expenses and may impose restrictions or limitations on the operation of the Company’s business, all of which could be substantial. Environmental, health and safety regulations may also require the Company to install new or updated pollution control equipment, modify its operations or perform other corrective actions at its facilities. Existing environmental laws and regulations may be revised to become more stringent or new laws or regulations may be adopted or become applicable to the Company which may result in increased compliance costs or additional operating restrictions and could reduce the Company’s earnings and harm the Company’s business, particularly if those costs are not fully recoverable from its customers through regulatory proceedings.

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Substantial operational risks are involved in operating a natural gas distribution, pipeline and storage system and such operational risks could adversely affect the Company’s revenues, earnings, cash flow and financial condition.

      There are substantial risks associated with the operation of a natural gas distribution, pipeline and storage system, such as operational hazards and unforeseen interruptions caused by events beyond the Company’s control. These include adverse weather conditions, accidents, the breakdown or failure of equipment or processes, the performance of pipeline facilities below expected levels of capacity and efficiency and catastrophic events such as explosions, fires, earthquakes, floods, landslides or other similar events beyond the Company’s control. These risks could result in injury or loss of life, property damage, business interruption or environmental pollution, which in turn could lead to substantial financial losses to the Company. In accordance with customary industry practice, the Company maintains insurance against some, but not all, of these risks. Liabilities incurred that were not fully covered by insurance could adversely affect the Company’s earnings, cash flow and financial condition. Additionally, interruptions to the operation of the Company’s gas distribution, pipeline or storage system caused by such an event could reduce revenues generated by the Company and, consequently, earnings and cash flow.

The Company’s ability to grow its businesses will be adversely affected if the Company is not successful in making acquisitions or in integrating the acquisitions it makes.

      One of the Company’s strategies is to grow through acquisitions. There is growing and significant competition for acquisitions in the U.S. natural gas industry, and the Company believes that there are numerous potential acquisition candidates, some of which represent opportunities that would be material to the Company. The Company cannot assure that it will find attractive acquisition candidates in the future, that it will be able to acquire such candidates on economically acceptable terms, that any acquisitions will not be dilutive to earnings or that any additional debt incurred to finance acquisitions will not impair its capitalization. The Company’s amended and restated three-year unsecured revolving bank credit facility for $120 million, which expires on September 15, 2008 (the “Bank Credit Agreement”) also limits the consideration the Company may pay in connection with any one acquisition to $50 million and in connection with all acquisitions occurring after September 15, 2005, to $150 million. These limitations will not apply to acquisitions occurring after the Company reaches certain investment grade debt ratings.

      In addition, the restructuring of the energy markets in the U.S. and internationally, including the privatization of government-owned utilities and the sale of utility-owned assets, is creating opportunities for, and competition from, well-capitalized existing competitors as well as new entrants to the markets, which may affect the Company’s ability to achieve this aspect of its business strategy.

      To the extent the Company is successful in making acquisitions, such acquisitions can involve a number of risks, including the assumption of material liabilities, the terms and conditions of any state or federal regulatory approvals required for the acquisitions, the diversion of management’s attention from the management of daily operations to the integration of operations, difficulties in the assimilation and retention of employees and difficulties in the assimilation of different cultures and practices, as well as in the assimilation of broad and geographically dispersed personnel and operations. The failure to successfully make and integrate acquisitions could have an adverse effect on the Company’s ability to grow its business.

Earnings and cash flow may be adversely affected by downturns in the economy.

      The Company’s operations are affected by the conditions and overall strength of the national, regional and local economies, which impact the amount of residential, industrial and commercial growth and actual gas consumption in the Company’s service territories. Many of the Company’s commercial and industrial customers use natural gas in the production of their products. During economic downturns, these customers may see a decrease in demand for their products, which in turn may lead to a decrease in the amount of natural gas they require for production. In addition, during periods of slow or little economic growth, energy conservation efforts often increase and the amount of uncollectible customer accounts often increases. These factors may reduce earnings and cash flow.

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The Company’s debt indentures and Bank Credit Agreement contain restrictive covenants that may reduce the Company’s flexibility, and adversely affect its business, earnings, cash flow, liquidity and financial condition.

      The terms of the indentures relating to certain of the Company’s outstanding debt securities and of the Company’s Bank Credit Agreement impose significant restrictions on the Company’s ability and, in some cases, the ability of the Company’s subsidiaries, to take a number of actions that the Company may otherwise desire to take, including:

•  requiring the Company to dedicate a substantial portion of its cash flow from operations to the payment of principal and interest on the Company’s indebtedness, thereby reducing the availability of cash flow for working capital, capital expenditures and other business activities;

•  requiring the Company to meet certain financial tests, which may affect the Company’s flexibility in planning for, or reacting to, changes in the Company’s business and the industries in which the Company operates;

•  limiting the Company’s ability to sell assets, make investments or acquire assets of, or merge or consolidate with, other companies;

•  limiting the Company’s ability to repurchase or redeem its stock or enter into transactions with its stockholders or affiliates; and

•  limiting the Company’s ability to grant liens, incur additional indebtedness or contingent obligations or obtain additional financing for working capital, capital expenditures, acquisitions and general corporate and other activities.

      These covenants place constraints on the Company’s business and may adversely affect its growth, business, earnings, cash flow, liquidity and financial condition. The Company’s failure to comply with any of the financial covenants in its Bank Credit Agreement may result in an event of default which, if not cured or waived, could result in the acceleration of the debt under the Company’s Bank Credit Agreement or the indentures governing its outstanding debt issuances that contain cross-acceleration or cross-default provisions. In such a case, there can be no assurance that the Company would be able to refinance or otherwise repay such indebtedness, which could result in a material adverse effect on its business, earnings, cash flow, liquidity and financial condition.

Adverse changes in the Company’s credit ratings may limit the Company’s access to capital, increase the Company’s cost of capital, increase the cost of maintaining certain contractual relationships or otherwise have a material adverse effect on the Company’s business, earnings, cash flow, liquidity and financial condition.

      In March 2003, Moody’s Investors Service, Inc. reduced the credit rating on the Company’s senior unsecured debt from Baa3 to Ba2. Since June 2003, Standard & Poor’s Ratings Group has lowered the Company’s corporate credit rating from BBB- to BB-. These downgrades have required the Company to pay higher interest rates for financing, increasing the Company’s cost of capital. Any additional downgrades could further increase the Company’s capital costs (including the rates for borrowing under the Company’s Bank Credit Agreement) and limit its pool of potential investors and funding sources, possibly increasing the costs of operations or requiring the Company to use a higher percentage of its available borrowing capacity for ordinary course purposes.

      Further credit downgrades could also negatively affect the terms on which the Company can purchase gas and pipeline capacity. As a result of the Company’s non-investment grade credit rating noted above, the interstate pipelines the Company utilizes require prepayment for their services. In addition, certain of the Company’s gas suppliers may require the Company to prepay or provide letters of credit for gas purchases over and above the levels of credit they may have extended to the Company. The Company can provide no assurance that suppliers will not impose additional requirements or restrictions on the conduct of the Company’s business.

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      The Company can provide no assurance that any of its current ratings will remain in effect for any given period of time or that a rating will not be lowered or withdrawn entirely by a rating agency. Any downgrade or other adverse action could adversely affect the Company’s business, earnings, cash flow, liquidity and financial condition.

The Company’s substantial indebtedness may limit its ability to borrow additional funds at all, or on reasonable terms, limit its growth and diminish its ability to respond to changing business and economic conditions and, thereby, may adversely affect its business, earnings, cash flow, liquidity and financial condition.

      The Company’s business is capital intensive and the Company has significant amounts of debt. At December 31, 2005, the Company had total short and long-term debt of $520.6 million. The Company’s substantial debt may adversely affect its business, earnings, cash flow, liquidity and financial condition. The Company’s substantial debt may, among other things:

•  limit the Company’s ability to borrow additional funds;

•  increase the cost of any future debt that the Company incurs;

•  reduce cash flow from operations available for working capital, capital expenditures and other general corporate purposes;

•  limit the Company’s flexibility in planning for, or reacting to, changes in its business and the industry in which it operates;

•  place the Company at a competitive disadvantage as compared to the Company’s competitors that are less highly leveraged;

•  result in a downgrade in the Company’s credit ratings; or

•  diminish the Company’s ability to successfully withstand a downturn in its business or the economy generally.

      The Company’s ability to meet its debt service obligations and to reduce its total indebtedness will depend upon its future performance, which will be subject to weather, general economic conditions, industry cycles and financial, business and other factors affecting the Company’s operations, many of which are beyond the Company’s control. No assurance can be provided that the Company’s business will generate sufficient cash flow from operations or that future borrowings will be available to the Company in an amount sufficient to enable the Company to pay its indebtedness or to fund its other liquidity needs. The Company may need to refinance all or a portion of its indebtedness on or before maturity. No assurance can be provided that the Company will be able to refinance any of its indebtedness, including its Bank Credit Agreement and its existing debt and debt securities, on commercially reasonable terms or at all.

Despite the Company’s substantial indebtedness, the Company may still be able to incur more debt, which could further exacerbate the risks associated with its substantial debt.

      Although the Company is presently limited in incurring additional indebtedness, the Company may be able to incur additional debt in the future. Restrictions applicable to the Company on the incurrence of additional debt contained in the indentures and Bank Credit Agreement governing the Company’s existing debt are subject to a number of qualifications and exceptions that allow the Company to incur additional debt. An increase in the amount of indebtedness may negatively affect the Company’s capital structure and credit ratings. If new debt is added to the Company’s current debt levels, the risks that the Company now faces could intensify.

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The Company is vulnerable to interest rate risk with respect to its debt which could lead to an increase in interest expense and a corresponding decrease in earnings and cash flow.

      The Company’s ability to finance capital expenditures and to refinance our maturing debt will depend in part on conditions in the capital markets, including rising interest rates. The Company’s cost of borrowing under its Bank Credit Agreement is also dependent on interest rates. In addition, in order to maintain the Company’s desired mix of fixed-rate and variable-rate debt, the Company may use interest rate swap agreements and exchange fixed and variable-rate interest payment obligations over the life of the arrangements, without exchange of the underlying principal amounts. No assurance can be provided that the Company will be successful in structuring such swap agreements to manage its risks effectively. If the Company is unable to do so, its earnings and cash flow may be reduced.

The Company’s Shareholder Rights Plan and other defensive mechanisms could make it more difficult for an acquisition bid for the Company or a change of control transaction to succeed.

      Certain provisions of the Company’s organizational documents, as well as other statutory and regulatory factors, may discourage or prevent acquisition offers that are in the best interests of the Company and its stockholders:

•  the Company’s Shareholder Rights Plan grants holders of its Common Stock certain rights upon the occurrence of certain triggering events unless a majority of independent directors on the Board of Directors (the “Board”) determines that the takeover offer is fair and otherwise in the best interests of the Company and its stockholders;

•  the Company’s articles of incorporation divide the Board into three classes that serve staggered terms, and directors may be elected by stockholders only at an annual meeting of stockholders or at a special meeting called for that purpose by the Board;

•  a director may be removed by stockholders but only for cause and only at an annual meeting of stockholders and by the affirmative vote of a majority of the shares then entitled to vote for the election of directors;

•  holders of the Preferred Stock have certain rights, including the right to receive a make-whole premium in connection with exercising their conversion rights in connection with a fundamental change, which would include certain acquisition offers;

•  the Bank Credit Agreement and certain of the Company’s debt indentures include provisions whereby the acquisition of a certain percentage of the Company’s Common Stock would be an event of default and cause the outstanding loans to become due and payable, or would require the Company to make an offer to holders of notes to repurchase outstanding notes at a premium;

•  unless the Board approves a business combination or the combination meets certain enumerated fairness standards, Michigan law requires the affirmative vote of 90% of the votes of each class of stock entitled to vote, and not less than two-thirds of the votes of each class of stock entitled to vote, voting as a separate class, to approve a business combination; and

•  Michigan law provides that control shares of a public company acquired in a control share acquisition have no voting rights except as granted by resolution approved by the stockholders of the company, effectively conditioning the acquisition of voting control of a corporation on the approval of a majority of pre-existing, disinterested stockholders.

In addition, the acquisition or accumulation of large blocks of the Company’s voting securities may require prior approval of the RCA and may result in the acquiring entity becoming subject to the jurisdiction of and regulation of the RCA and, notwithstanding the repeal of the Public Utility Holding Company Act of 1935, to other state or federal regulation as a public utility holding company. These consequences would result in substantial increases in that entity’s administrative, legal and regulatory compliance costs and could have similar adverse consequences for the Company.

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Item 1B.     Unresolved Staff Comments

      None.

Item 2. Properties

Gas Distribution Business Segment

      The natural gas transmission and delivery system of SEMCO Gas included approximately 160 miles of gas transmission pipelines and 5,591 miles of gas distribution mains and service lines at December 31, 2005. The pipelines, mains and service lines are located throughout the southern half of Michigan’s lower peninsula (centered in and around the cities of Albion, Battle Creek, Holland, Niles, Port Huron and Three Rivers) and also in the central and western areas of Michigan’s Upper Peninsula. At December 31, 2005, ENSTAR’s natural gas delivery system (including APC’s natural gas transmission system) included approximately 393 miles of gas transmission pipelines and 2,650 miles of gas distribution mains and service lines. ENSTAR’s pipelines, mains and service lines are located in Anchorage and the Cook Inlet area.

      The distribution mains and service lines of the Gas Distribution Business are, for the most part, located on or under public streets, alleys, highways and other public places, or on private property not owned by the Company with permission or consent, except to an inconsequential extent, of the individual property owners. The distribution mains and service lines located on or under public streets, alleys, highways and other public places were installed under valid rights and consents granted by appropriate local authorities.

      The Gas Distribution Business owns underground gas storage facilities in eight depleted salt caverns and three depleted gas fields, together with related measuring, compressor and transmission facilities. The storage facilities are all located in Michigan. The aggregate working capacity of the storage system is approximately 5.1 Bcf.

      The Gas Distribution Business also owns meters and service lines, gas regulating and metering stations, garages, warehouses and other buildings necessary and useful in conducting its business. In addition, the Gas Distribution Business leases a significant portion of its transportation equipment and certain buildings.

Corporate and Other

      The principal properties of this segment include interests and operations in IT services, propane distribution, natural gas transmission pipelines, an underground gas storage system and general corporate facilities supporting these operations.

      The properties of the Company’s IT services business consist of a building, office equipment, telecommunications equipment and computer equipment. The building is located in Marysville, Michigan, and houses this equipment.

      The property of the propane distribution operation consists primarily of pressurized propane storage tanks used by customers to store propane purchased from the Company and trucks for transporting propane. The Company also owns large propane storage tanks that allow the Company to store up to 258,000 gallons of propane inventory. The propane distribution property is located in Michigan’s Upper Peninsula and northeast Wisconsin.

      The Company owns a 50% equity interest in the ERGSS. The Company’s equity investment in the ERGSS totaled approximately $6.9 million at December 31, 2005. This natural gas storage system, located near Eaton Rapids, Michigan, became operational in March 1990 and consists of approximately 12.8 Bcf of underground storage capacity. The Gas Distribution Business leases 6.5 Bcf of the capacity.

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      The following table sets forth the natural gas pipeline operations wholly or partially owned by the Company, the total net property of each system, and the Company’s ownership percentage and net property in each system at December 31, 2005:

	Total Net		The Company’s			The Company’s
	Property		Percent Ownership			Net Property
	(In thousands, except percents)
Litchfield Lateral	$	7,230		33	%	$	2,410
Greenwood Pipeline		4,553		100	%		4,553
Eaton Rapids Pipeline		382		100	%		382
	$	12,165				$	7,345

      The Litchfield Lateral is a31-mile pipeline located in southwest Michigan. The line, which is leased entirely to ANR Pipeline Company, links the ERGSS with interstate pipeline supplies. The Greenwood Pipeline, is an17-mile pipeline that connects an interstate pipeline with the DTE Energy Greenwood Power Plant located near Port Huron, Michigan. The pipeline provides transportation services to the Greenwood Power Plant and also supplies the Gas Distribution Business’ service area north of Port Huron, Michigan. The Eaton Rapids Pipeline is a37-mile pipeline that delivers gas from the ERGSS to the Gas Distribution Business’ systems in Battle Creek and Albion, Michigan.

      The Company’s corporate division is a cost center rather than a business segment. The properties of the corporate division primarily include leasehold improvements, office furniture, office equipment, computers and computer systems. These properties are located in a leased office building in Port Huron, Michigan (which houses the Company’s headquarters), and leased satellite office space in Troy, Michigan.

Item 3. Legal Proceedings

      In the normal course of business, the Company may be a party to lawsuits and administrative proceedings before various courts and government agencies. The Company also may be involved in private dispute resolution proceedings. These lawsuits and proceedings may involve personal injury, property damage, contractual issues and other matters (including alleged violations of federal, state and local laws, rules, regulations and orders). Management cannot predict the outcome or timing of any pending or threatened litigation or of actual or possible claims. Except as otherwise stated, management believes resulting liabilities, if any, will not have a material adverse impact upon the Company’s financial position, results of operations, or cash flows.

      In October 2004, two Company subsidiaries (SEMCO Energy Services, Inc. and SEMCO Pipeline Company) were added as defendants in a putative class action lawsuit brought in federal district court in West Virginia alleging that the approximately 30 defendants named in the lawsuit engaged in gas marketing activities that violated state and federal anti-trust laws and otherwise tortiously interfered with the business opportunities of the plaintiffs from 1996 to present. On October 4, 2005, the court granted a motion to dismiss filed by certain defendants, including the Company’s subsidiaries, as to federal anti-trust claims arising prior to October 25, 2000. On January 30, 2006, the court declined a request that it amend its dismissal order to include any state anti-trust claims arising during the same period. The Company plans to file additional motions raising defenses with respect to all remaining claims. The Company sold its gas marketing business in 1999.

      In connection with the issuance of its 6% Series B Convertible Preference Stock (“Convertible Preference Stock” or “CPS”) and Common Stock warrants (“Warrants”) to K-1 GHM, LLLP, an affiliate of a private equity firm, k-1 Ventures Limited (“K-1”), during 2004, the Company agreed to seek certain rulings from the RCA. As part of RCA proceedings instituted with respect to the rulings sought by the Company, the Alaska Attorney General asserted, among other things, that (i) the Company’s issuance of the CPS and Warrants to K-1 resulted in a control change requiring prior approval by the RCA, (ii) such a control change did not adversely affect ENSTAR and therefore should be approved by the RCA, and (iii), in connection with approving this control change, the RCA should institute a rate proceeding to review the base rates of

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ENSTAR, using a 2005 test year and a new depreciation study for ENSTAR’s property. The Company believed that no control change occurred upon the issuance of the CPS and Warrants to K-1 and thus no RCA approval was required. The Company also opposed the proposal that the RCA institute a rate proceeding to review ENSTAR’s base rates and, in connection with that review, order that a depreciation study of ENSTAR’s property be done.

      After repurchasing the CPS and Warrants from K-1 on March 15, 2005, the Company filed a motion to terminate proceedings with the RCA on the basis that the repurchase made such proceedings moot. The Company also continued to oppose the proposal that the RCA institute a rate proceeding to review ENSTAR’s base rates and conduct a depreciation study. On June 20, 2005, the RCA terminated the proceeding. It also required ENSTAR to file a revenue requirement and cost of service study (including rate design data) with the RCA by June 6, 2008 (using a test year ended December 31, 2007). In addition, ENSTAR is required to file a depreciation study of utility plant (as of December 31, 2006) by June 1, 2007. These filings also will include the Company’s APC subsidiary.

      In September 2002, the Company agreed to relocate its headquarters to Port Huron, Michigan, and leased part of a new office building in Port Huron from Acheson Ventures LLC (“Acheson”). As part of the transaction, Acheson agreed to sublease office space occupied by the Company in Farmington Hills, Michigan, and, beginning in February 2005, began to pay the Company’s Farmington Hills lease costs (approximately $36,000 per month until March 31, 2011, when the Farmington Hills lease expires), as agreed. In June 2005, Acheson ceased making these payments, ostensibly because the Company had breached its obligations by maintaining a satellite office in Troy, Michigan, for certain executives who also have offices in the Company’s Port Huron headquarters. The Company has filed an action in Michigan state court, seeking (i) damages for Acheson’s failure to pay the Company’s Farmington Hills lease costs, and (ii) a declaratory judgment that the Company has met its obligations to Acheson. To mitigate its damages, the Company is paying the Farmington Hills lease costs and is attempting to market the space to prospective subtenants. On January 16, 2006, Acheson answered the Company’s complaint, filed counter-claims alleging breach of contract, fraud, and negligent misrepresentation, and sought a change of venue for these proceedings, to Port Huron, Michigan. The Company has made filings to answer Acheson’s counter claims, denying any liability to Acheson, and opposing a change of venue.

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

      No matter was submitted to a vote of security holders during the fourth quarter of 2005.

PART II

Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

      The Company’s Common Stock began trading on the NYSE on January 6, 2000, with the trading symbol “SEN.” The table below shows the reported high and low sales prices of the Company’s Common Stock during 2005 and 2004, as reported on the NYSE.

	2005 Price
	Range
Quarter	High		Low
First Quarter	$	6.24	$	5.10
Second Quarter	$	6.19	$	5.00
Third Quarter	$	7.05	$	5.82
Fourth Quarter	$	6.85	$	5.16

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	2004 Price
	Range
Quarter	High		Low
First Quarter	$	6.38	$	4.80
Second Quarter	$	6.35	$	5.00
Third Quarter	$	5.88	$	4.86
Fourth Quarter	$	5.74	$	4.50

      At February 28, 2006, the closing price of the Company’s Common Stock was $5.60 per share and the Company had 33,726,152 shares of Common Stock outstanding and had 7,909 registered holders of its Common Stock.

      For information regarding dividends, see Item 6 of this Form 10-K and Notes 4 and 15 of the Notes to the Consolidated Financial Statements in Item 8 of this Form 10-K.

      For information relating to compensation plans under which equity securities of the Company are authorized for issuance, see Item 12 of this Form 10-K.

      During the fourth quarter of 2005, the Company issued an aggregate of 474 shares of unregistered Common Stock, valued at approximately $3,081, to members of the Board pursuant to an equity compensation plan described in the Company’s definitive Proxy Statement (filed pursuant to Regulation 14A), incorporated by reference in Item 12 of this Form 10-K. The transactions were exempt from registration under Section 4(2) of the Securities Act of 1933, as amended.

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Item 6. Selected Financial Data

      The following tables set forth selected financial and operating data. The selected financial data presented below as of December 31, 2001, and for the year then ended, have been derived from the Company’s consolidated financial statements that were audited by Arthur Andersen LLP. The selected financial data presented below as of December 31, 2002, 2003, 2004 and 2005, and for each of the four years then ended, have been derived from the Company’s consolidated financial statements that were audited by PricewaterhouseCoopers LLP. The selected financial data presented below should be read in conjunction with the Company’s consolidated financial statements and the Notes to the Company’s Consolidated Financial Statements in Item 8 of this Form 10-K and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Item 7 of this Form 10-K.

			Years Ended December 31,
			2005			2004			2003			2002			2001
			(In thousands, except per share amounts)
Statement of operations data
	Operating revenues		$	615,102		$	508,336		$	472,955		$	374,162		$	328,663
	Operating expenses
		Cost of gas sold	$	443,860		$	346,241		$	308,919		$	220,422		$	184,973
		Operations and maintenance(a)		71,913			75,883			65,152			54,373			55,493
		Depreciation and amortization		28,224			27,578			27,448			27,127			28,887
		Property and other taxes		11,601			13,149			10,739			10,816			10,554
			$	555,598		$	462,851		$	412,258		$	312,738		$	279,907
	Operating Income		$	59,504		$	45,485		$	60,697		$	61,424		$	48,756
	Other income (deductions)(b)			(41,746	)		(41,796	)		(61,561	)		(27,647	)		(27,418	)
	Income (loss) before income taxes and minority interest		$	17,758		$	3,689		$	(864	)	$	33,777		$	21,338
	Income tax (expense) benefit			(6,021	)		467			80			(13,005	)		(7,100	)
	Minority interest, net of income tax benefit			—			—			(4,300	)		(8,601	)		(8,603	)
	Income (loss) from continuing operations		$	11,737		$	4,156		$	(5,084	)	$	12,171		$	5,635
	Discontinued operations, net of income tax			538			(9,339	)		(24,871	)		(3,222	)		(11,996	)
	Net income (loss)		$	12,275		$	(5,183	)	$	(29,955	)	$	8,949		$	(6,361	)
	Dividends on convertible cumulative preferred stock			2,994			—			—			—			—
	Dividends and repurchase premium on convertible preference stock			9,112			3,203			—			—			—
	Net income (loss) available to common shareholders		$	169		$	(8,386	)	$	(29,955	)	$	8,949		$	(6,361	)

(a)	2004 includes $8,398 of expenses related to the terminated sale of a subsidiary and a $152 goodwill impairment charge and 2001 includes $3,005 for restructuring and asset impairment charges.
(b)	2005 includes debt extinguishment expenses of $1,456 and 2003 includes debt exchange and extinguishment expenses of $24,030.

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			Years Ended December 31,
			2005			2004			2003			2002		2001
			(In thousands, except per share amounts)
Common stock and per share data
	Average shares outstanding (in thousands)
		Basic		30,408			28,263			22,297			18,472		18,106
		Diluted		30,408			28,296			22,297			18,493		18,106
	Earnings per share on income (loss) from continuing operations
		Basic	$	(0.01	)	$	0.03		$	(0.23	)	$	0.66	$	0.31
		Diluted	$	(0.01	)	$	0.03		$	(0.23	)	$	0.66	$	0.31
	Earnings per share on net income (loss) available to common shareholders
		Basic	$	0.01		$	(0.30	)	$	(1.34	)	$	0.48	$	(0.35	)
		Diluted	$	0.01		$	(0.30	)	$	(1.34	)	$	0.48	$	(0.35	)
	Dividends declared per share		$	—		$	0.08		$	0.35		$	0.50	$	0.84
Statement of financial position data at December 31
	Total assets		$	1,016,555		$	926,198		$	951,219		$	927,703	$	905,094
	Capitalization
		Long-term debt, including current maturities(a)	$	441,659		$	498,427		$	529,007		$	505,462	$	508,360
		Convertible cumulative preferred stock		66,526			—			—			—		—
		Series B convertible preference stock		—			48,405			—			—		—
		Common shareholders’ equity		194,000			166,086			174,418			110,022		113,810
	Total Capitalization		$	702,185		$	712,918		$	703,425		$	615,484	$	622,170

(a) Includes Company-obligated mandatorily redeemable trust preferred securities for 2002 and 2001.

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operation

Business Strategy Summary

      The Company is primarily a regulated natural gas distribution company with operations in Michigan and Alaska. The Company provides natural gas service to approximately 409,000 customers, with approximately 286,000 customers in Michigan and 123,000 customers in Alaska. Approximately 90% of the Company’s market consists of residential customers. The Company’s Gas Distribution Business sells a significant portion of gas to customers for heating purposes and, therefore, is a seasonal business. As a result, earnings are significantly influenced by the weather and concentrated in the first and fourth fiscal quarters of the year. The Company typically experiences net losses during the non-heating season, which takes place in the second and third fiscal quarters of the year. The Company’s business is regulated by the MPSC, CCBC, and RCA.

      The Company’s current strategic focus remains two-fold. First, the Company continues to seek to improve its financial performance by enhancing financial flexibility through cost control and improving credit quality. In 2006, this effort is expected to include containing its controllable costs (including capital expenditures and operation and maintenance expenses). The Company is also considering (i) seeking MPSC and RCA approval of possible changes in the methods by which the Company charges customers for natural gas service (which is known in the industry as “rate design”), and (ii) depending on analyses of the Company’s revenue needs, seeking approval of increases in the rates the Company’s charges customers for natural gas service in jurisdictions where doing so is warranted and otherwise considered achievable. An analysis of possible rate design proposals is currently under way, including an assessment of the relative merits

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of various alternative ways of collecting revenues from customers. A primary focus of this effort is to attempt to devise acceptable revenue collection methods that address the impact of higher and more volatile gas prices on the Company. Analyses of the Company’s need for additional revenue, by jurisdiction, will be performed using 2005 year-end data, again with a view towards assessing that need (if any) and other aspects of any base rate increase proposals, including the expected receptivity of regulatory agencies where such requests would be filed, to such proposals and the relationships (if any) between possible rate increase proposals and the Company’s rate design proposals, when finalized. Part of the analysis of the Company’s need for additional revenue is expected to involve an assessment of ratemaking conventions that affect the calculation of revenues the Company is authorized to collect and the need for, and acceptability of, changes in such conventions.

      Upon completion of the analyses of the Company’s need for additional revenue, with respect to the Company’s MPSC-regulated service area, it is anticipated that the Company will have a revenue deficiency in connection with its allowed rate of return, using a 2005 test year. Also, under current rate designs in Michigan, the Company believes it is disadvantaged in achieving its authorized return, given the current higher and more volatile natural gas price environment. Of particular concern are declining consumption per customer, higher bad debt expense, increased lost and unaccounted for (“LAUF”) gas expense, higher working capital requirements, and conventions used to estimate the impact of weather on the Company’s revenues. Depending on the results of the analyses of the Company’s need for additional revenues and rate design alternatives, the Company would expect to file for base rate changes and/or rate design changes for its MPSC-regulated service area during the second quarter of 2006.

      The second aspect of the Company’s strategic focus is growing its Gas Distribution Business (including related pipeline and storage operations) by seeking to make appropriate acquisitions and investments in Michigan, Alaska, and elsewhere. The Company’s ability to make such acquisitions and investments will be affected by efforts to improve the Company’s financial condition described above and elsewhere in this Form 10-K as well as by the availability of appropriate acquisition and investment opportunities and the ability to consummate any such transactions on reasonable terms.

      It is the Company’s intent that any such acquisitions and investments, which typically would be subject to federal and state regulatory approvals, would be accretive to earnings. It is unlikely, however, that such acquisitions and investments, if made, would significantly change the profile of the Company’s business, since any natural gas distribution, pipeline or storage operations the Company would acquire would likely share the characteristic of having earnings that are significantly influenced by the weather. Such acquisitions and investments also would likely involve companies that are subject to regulation with respect to services, rates, and other terms and conditions of service by federal, state, and local regulatory bodies.

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Summary of Results of Operations

      The discussions in this section are summarized and intended to provide an overview of the results of Company operations. In most instances, the items discussed here are covered in greater detail in later sections of Management’s Discussion and Analysis. Any variances in results in this section are quantified on an after-tax basis. The Company uses an effective income tax rate of 36.8% to estimate these after-tax amounts. All references to earnings or losses per share (“EPS”) in Management’s Discussion and Analysis are on a fully diluted basis. For information related to the calculation of diluted EPS, refer to Note 10 of the Notes to the Consolidated Financial Statements in Item 8 of this Form 10-K. The following table summarizes the Company’s operating results for the past three years:

		Years Ended December 31,
		2005			2004			2003
		(In thousands, except per share
		amounts)
Operating revenues		$	615,102		$	508,336		$	472,955
	Operating expenses		555,598			462,851			412,258
Operating income		$	59,504		$	45,485		$	60,697
	Other income (deductions)		(41,746	)		(41,796	)		(61,561	)
	Income tax (expense) benefit		(6,021	)		467			80
	Minority interest — dividends on trust preferred securities, net of income tax benefit		—			—			(4,300	)
Income (loss) from continuing operations		$	11,737		$	4,156		$	(5,084	)
Income (loss) from discontinued operations, net of income tax			538			(9,339	)		(24,871	)
Net income (loss)		$	12,275		$	(5,183	)	$	(29,955	)
Dividends on convertible cumulative preferred stock			2,994			—			—
Dividends and repurchase premium on convertible preference stock			9,112			3,203			—
Net income (loss) available to common shareholders		$	169		$	(8,386	)	$	(29,955	)
Earnings per share — basic
	Income (loss) from continuing operations	$	(0.01	)	$	0.03		$	(0.23	)
	Net income (loss) available to common shareholders	$	0.01		$	(0.30	)	$	(1.34	)
Earnings per share — diluted
	Income (loss) from continuing operations	$	(0.01	)	$	0.03		$	(0.23	)
	Net income (loss) available to common shareholders	$	0.01		$	(0.30	)	$	(1.34	)
Average common shares outstanding — basic			30,408			28,263			22,297
Average common shares outstanding — diluted			30,408			28,296			22,297

     Comparison of 2005 and 2004 results. The Company’s $0.2 million of net income available to common shareholders for 2005 is an $8.6 million improvement over 2004 results. There were a number of offsetting factors that impacted net income available to common shareholders. The primary factors that improved 2005 results, when compared to 2004, were: an increase in gas sales margin and other gas distribution revenue; the absence from 2005 results of expenses associated with the terminated sale of the Company’s APC subsidiary; changes in results from discontinued operations ($0.5 million of income in 2005 compared to $9.3 million of losses in 2004); and a decrease in property and other taxes. The increase in gas sales margin and other gas distribution revenue increased net income by approximately $6.6 million and was attributed in large part to rate increases in Michigan and the addition of new customers, partially offset by a decrease in gas consumption by customers. The expenses included in 2004 results for the Company’s APC subsidiary include costs associated with an arbitration proceeding over the termination of the Company’s sale of the APC subsidiary and a payment by the Company to settle the matter. These APC-related expenses increased the 2004 net loss by approximately $5.3 million. The decrease in property and other tax expense increased 2005 net income by approximately $1.0 million.

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      The primary factors that negatively impacted earnings for 2005, when compared to 2004, were: a premium associated with the repurchase of the CPS; a non-cash debt extinguishment charge; increases in operations and maintenance expenses; increased depreciation expense; and the absence from 2005 results of state income tax benefits recorded in 2004. The premium associated with the repurchase of the CPS decreased net income by approximately $8.2 million. The non-cash debt extinguishment charge, which represents the write-off of unamortized debt issuance costs associated with long-term debt retired in 2005, decreased net income by approximately $0.9 million. The increase in operations and maintenance expenses, which decreased net income by approximately $2.9 million, was due primarily to increases in employee benefit and incentive costs, compensation, facilities costs, uncollectible customer accounts and various other operating expenses, due to the increasing cost of doing business. The increase in depreciation expense reduced net income by approximately $0.4 million. The state income tax benefits recorded in 2004 amounted to approximately $2.2 million and related to a change in estimate of the Company’s prior years state income taxes. Combined financing costs for 2005, which include interest expense and dividends on both the CPS and newly-issued Preferred Stock, were essentially unchanged from 2004.

     Comparison of 2004 and 2003 results. The $8.4 million net loss available to common shareholders for 2004 is a $21.6 million improvement over 2003 results. There were a number of offsetting factors that impacted the net loss available to common shareholders. The primary factors that improved earnings for 2004, when compared to 2003, were: a $15.5 million decrease in losses from the Company’s discontinued construction services business; the non-recurrence in 2004 of $15.2 million of debt exchange and extinguishment costs recorded in 2003; and a change in estimate of the Company’s prior years state income taxes, which resulted in an additional income tax benefit of approximately $2.2 million in 2004.

      The primary factors that negatively impacted earnings for 2004, when compared to 2003, were: a decrease in gas sales margin; the previously discussed APC-related expenses incurred in 2004; and increases in operations and maintenance expenses and financing costs. The decrease in gas sales margin, which increased the net loss for 2004 by approximately $1.2 million, was largely caused by a decrease in gas consumption by customers and an increase in LAUF gas expense partially offset by gas sales margins from new customers. The increase in operations and maintenance expenses increased the 2004 net loss by approximately $1.4 million and the increase in financing costs increased the net loss by approximately $1.8 million.

      The business segment analysis and other discussions on the next several pages provide additional information regarding the differences in operating results when comparing 2005, 2004 and 2003.

The Impact of Higher Natural Gas Prices

      The market price of natural gas increased substantially during the second half of 2005. The Company believes that such price increases were caused, in large part, by the impact of Hurricanes Katrina and Rita on drilling, production, pipelines and processing facilities in and around the Gulf of Mexico, along with the supporting infrastructure and resources for those facilities. The Company also believes that higher natural gas prices may persist or remain volatile even after hurricane-related damage to production and other facilities is repaired, due to an apparent imbalance between natural gas supplies and demand resulting from, among other factors, the use of substantial amounts of natural gas to generate electricity and environmental and other restrictions on natural gas exploration and production.

      For customers in its Michigan service areas, the Company purchases natural gas supplies throughout the year, in order to (i) meet current customer needs, (ii) inject gas into storage for use by customers during the winter heating season, and (iii) have sufficient supplies under contract for the winter heating season. Recent natural gas purchases for customers in the Company’s Michigan gas service areas have, and future purchases are expected to, cost significantly more than purchases during prior years due to the increase in natural gas prices. Since mid-December 2005, natural gas prices have receded from their peak levels established earlier in December 2005. The recent decline in prices may be attributable, among other factors, to reduced customer gas consumption in reaction to high prices, relatively warm weather in January 2006 throughout the midwestern and eastern portions of the United States and relatively high levels of working gas in storage in comparison to average levels over the last five years. Despite the recent pullback in natural gas prices, future

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prices still remain relatively high for the upcoming 2006-2007 winter heating season. Additionally, since the majority of the Company’s Michigan gas procurement for the 2005-2006 winter heating season occurred throughout 2005, the recent reduction in natural gas prices is not expected to impact the gas commodity portion of customer rates substantially until after the 2005-2006 winter heating season has passed. Approximately 45% to 48% of annual Michigan sales volumes typically occur in the first quarter of each year, so nearly half of the Company’s 2006 gas sales in Michigan will have occurred before there would be any significant decrease in the gas commodity portion of customer rates.

      For customers in Alaska, the Company’s facilities are located near natural gas supplies, and the Company has RCA-approved gas purchase contracts with various Cook Inlet area producers. The price of gas purchased under these contracts is adjusted annually in January. Much of the natural gas purchased by the Company for its Alaska customers is priced on trailing average prices for oil and natural gas, so recent price increases are not yet fully reflected in the price the Company is currently paying for gas sold to customers in its Alaska service area. However, gas prices under these contracts have increased over the past few years and, based on these trailing average prices, are expected to increase in the future.

      In general, the costs of natural gas purchased for customers are recovered on a dollar-for-dollar basis (in the absence of regulatory disallowances), without a profit. The recovery of these gas costs is accomplished through the Company’s GCR pricing mechanisms, through which customer rates are periodically adjusted for increases and decreases in the cost of gas purchased by the Company for sale to customers. Refer to the caption “Cost of Gas, Gas Charges Recoverable from Customers, and Amounts Payable to Customers” in Note 1 of the Notes to the Consolidated Financial Statements in Item 8 of this Form 10-K for additional information on the GCR pricing mechanisms.

      When gas costs increase substantially (such as has been the case recently), the Company may require regulatory approval in certain of its regulatory jurisdictions to increase the commodity, or GCR, component of rates, to ensure the timely recovery of the cost of gas purchased for sale to customers. In addition, higher gas costs may increase delinquent or uncollectible accounts, increase the value of LAUF gas and decrease customer consumption. These and other factors could result in an increase in working capital requirements and the need for the Company to borrow additional amounts under its Bank Credit Agreement.

      The Company has been addressing, and continues to address, the likely impact of higher natural gas prices by (i) seeking GCR rate increases in Michigan to recover the cost of gas on a timely basis, (ii) closely monitoring customer payment patterns in Michigan and Alaska, encouraging the use of budget-type levelized payment plans and referring customers to sources of charitable and public assistance, (iii) attempting to secure MPSC approval to recover the commodity costs associated with LAUF gas and uncollectibles in the GCR component of rates or in another way that would reflect actual costs incurred by the Company, and (iv) monitoring the impact of higher gas costs on customer consumption and the Company’s working capital. In addition, the Company is assessing the need for changes in rate design, changes in ratemaking conventions, and increases in revenues to be collected from customers, with a view towards addressing, among other things, the impact of higher and more volatile natural gas prices.

      The MPSC-approved GCR rate affects approximately 249,000 customers in the Company’s service territory regulated by the MPSC. In October 2005, the MPSC approved a settlement under which the Company increased its GCR rate to recover the increases in the cost of natural gas purchased by the Company for sale to customers. The GCR rate for the approximately 37,000 customers in the service territory regulated by the CCBC is revised monthly, to track and recover changes in the cost of natural gas purchased by the Company for use by Battle Creek area customers. The GCR rate for the approximately 120,000 customers in Alaska is established annually in January by the RCA to reflect the pricing mechanisms in certain long-term gas supply contracts approved by the RCA and, recovers the cost of natural gas purchased by the Company under those contracts.

      Higher gas costs, to the extent they are reflected in revised rates, may affect the ability of some customers to pay their bills for gas service on time or in full. The Company plans to monitor customer payment patterns closely and has been and is encouraging customers to elect budget-type levelized payment plans, to spread winter heating season bills over a twelve-month period. In addition to cutting off service to delinquent

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customers, as necessary and permitted, the Company will refer customers to sources of charitable and public assistance. The Company participates in efforts to secure charitable donations that will provide such assistance.

      The Company’s uncollectibles expense for gas sales customers as a percent of gas sales revenue was 0.50% in 2003, 0.43% in 2004 and 0.42% for 2005. Assuming that future uncollectibles expense as a percent of gas sales revenue is similar to the experience in 2005, for each 10% increase in gas sales revenue (principally driven by the change in natural gas prices), there would be an expected increase in uncollectibles of approximately $0.2 million. The Company cannot provide any assurance that its future uncollectibles expense will be consistent with its prior experience, in view of the increased cost of natural gas and related rate increases and other factors affecting customer payment patterns.

      The Company also expects that higher gas costs will increase the expense associated with LAUF gas in its Michigan service areas, assuming that LAUF volumes are consistent with LAUF volumes in prior periods. Annual LAUF volumes in Michigan have ranged from 0.5% to 1.4% of volumes sold and transported in the Company’s Michigan service area over the last 10 years. The Company’s Michigan gas distribution operation typically accounts for 48% to 57% of total volumes sold and transported by the Company.

      The Company also believes that higher gas costs, to the extent they are reflected in rates, have affected, and may continue to affect, gas consumption by customers, who are induced by higher prices to conserve. The Company is unable to estimate the amount of conservation (if any) that is likely to occur. However, the Company estimates that every one percent decrease in customer consumption in Michigan may cause a decrease in gas sales margin of $0.2 million to $0.3 million for the first quarter of 2006. The Company estimates that every one percent decrease in customer consumption in Alaska may cause a decrease in gas sales margin of $0.1 million to $0.2 million for the first quarter of 2006.

      The Company expects that higher gas costs will increase its need for working capital to finance gas purchases at higher market prices, finance storage inventory, carry accounts receivables, and carry any under-recovery of gas costs not recouped in current rates. The Company uses its Bank Credit Agreement to fund its working capital requirements, which normally peak around year-end or in early-January due to the seasonal nature of the Company’s business. The Company expects that its Bank Credit Agreement will provide sufficient borrowing capacity to fund working capital requirements through the 2005-06 winter heating season.

The Impact of Weather and Energy Conservation

      Temperature fluctuations and energy conservation have a significant impact on operating results of the Company. Accordingly, the Company believes that information about normal temperatures and consumption is useful for understanding its business and operating results. Consumption of natural gas for heating is largely determined by weather, and a portion of the Company’s revenues are collected through consumption-based charges. The Company’s budgets, forecasts and business plans are prepared using expected gas consumption under normal weather conditions and historical consumption patterns. The regulatory bodies that have jurisdiction over the rates charged by the Gas Distribution Business use weather-normalized consumption data to set customer rates and to establish authorized rates of return.

      Many of the Company’s customers appear to be continuing a pattern of conserving energy by utilizing energy efficient heating systems, insulation, alternative energy sources, and other energy saving devices and techniques. During the past several years, average annual gas consumption has been decreasing. In addition, increases in natural gas prices appear to have increased conservation efforts by customers. The Company expects this conservation trend to continue as an era of higher and more volatile natural gas prices influences customer consumption.

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      The following table provides temperature and customer consumption data for the years 2003 through 2005:

				Years Ended December 31,
				2005			2004			2003
Michigan
	Degree days (DD)(a)
		Actual			6,689			6,726			7,063
		Normal(b)			6,694			6,747			6,746
		Actual DD as a percent of normal DD			99.9	%		99.7	%		104.7	%
		Percent by which actual DD differ from:
			Normal DD(c)		(0.1	)%		(0.3	)%		4.7	%
			Prior year actual DD(d)		(0.6	)%		(4.8	)%		5.9	%
	Average annual gas consumption per customer (Mcf)
		Residential gas sales customers			103.7			107.8			116.7
		Residential gas sales customers normalized(e)			103.8			108.1			111.5
		Percent by which residential gas sales customers normalized differs from prior year residential gas sales customers normalized(f)			(4.0	)%		(3.0	)%		(0.7	)%
		All gas sales customers			146.1			152.7			163.2
		All gas sales customers normalized(e)			146.2			153.2			155.9
		Percent by which all gas sales customers normalized differs from prior year all gas sales customers normalized(f)			(4.5	)%		(1.7	)%		(3.8	)%
Alaska
	Degree days (DD)(a)
		Actual			9,572			9,573			9,384
		Normal(b)			10,151			10,187			10,204
		Actual DD as a percent of normal DD			94.3	%		94.0	%		92.0	%
		Percent by which actual DD differ from:
			Normal DD(c)		(5.7	)%		(6.0	)%		(8.0	)%
			Prior year actual DD(d)		(0.0	)%		2.0	%		(0.1	)%
	Average annual gas consumption per customer (Mcf)
		Residential gas sales customers			165.2			173.4			166.7
		Residential gas sales customers normalized(e)			175.2			184.5			181.3
		Percent by which residential gas sales customers normalized differs from prior year residential gas sales customers normalized(f)			(5.1	)%		1.8	%		0.9	%
		All gas sales customers			197.3			208.1			203.8
		All gas sales customers normalized(e)			209.2			221.4			221.6
		Percent by which all gas sales customers normalized differs from prior year all gas sales customers normalized(f)			(5.5	)%		(0.1	)%		(0.0	)%

(a)	Degree days are a measure of coldness determined daily as the number of degrees the average temperature during the day in question is below 65 degrees Fahrenheit. Degree days for a particular year are determined by adding the degree days incurred during each day of the year.
(b)	Normal degree days for a particular year is the average of degree days during the prior fifteen years. Beginning in 2006, the Company plans to determine normal degree days for its Alaska operations using aten-year average of degree days rather than afifteen-year average.
(c)	The percent by which actual degree days differ from normal degree days is often referred to as the percent by which temperatures were colder (warmer) than normal.
(d)	The percent by which actual degree days differ from prior year actual degree days is often referred to as the percent by which temperatures were colder (warmer) than the prior year.
(e)	Normalized average annual gas consumption is determined by dividing the actual average annual gas consumption by actual degree days as a percent of normal degree days. The normalized average annual gas consumption represents an estimate of what average annual gas consumption would have been if during the period in question, actual degree days had equaled normal degree days.
(f)	The percent by which normalized average annual gas consumption differs from prior year normalized average annual gas consumption represents an estimate of the percentage change in gas consumption from one year to the next caused by factors other than temperature variations. This change can relate to various factors but is most likely due to changes in energy conservation by customers.

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     The Company has estimated that in its Michigan service area, temperatures were approximately 0.1% and 0.3% warmer than normal during 2005 and 2004, respectively, and approximately 4.7% colder than normal during 2003. In the Company’s Alaska service area, temperatures were estimated to be approximately 5.7%, 6.0% and 8.0% warmer than normal during 2005, 2004 and 2003, respectively.

      Normalized average annual gas consumption for all gas sales customers in the Company’s Michigan and Alaska service areas decreased in 2005 by a larger percentage than in previous years. The Company has estimated that in its Michigan service area, normalized average annual gas consumption during 2005 for all gas sales customers decreased by approximately 4.5%, when compared to 2004. In the Company’s Alaska service area, normalized average annual gas consumption during 2005 for all gas sales customers decreased by an estimated 5.5%, when compared to 2004.

      The Company estimates that the combined variations from normal temperatures and normalized gas consumption decreased net income by approximately $3.3 million in 2005 and approximately $2.0 million during 2004. These estimates reflect the adoption of new methodologies that are designed to more accurately estimate the impact of combined variations from normal temperatures and normalized gas consumption. The Company estimates the impact on its operating results of combined variations from normal temperatures and normalized gas consumption by comparing average annual gas consumption per customer during a year to the normalized average annual gas consumption per customer for the prior year. The difference is multiplied by the average number of customers during the year to arrive at the total estimated increase or decrease in consumption associated with the combined variations from normal temperatures and normalized gas consumption. The total increase or decrease in consumption is multiplied by the actual gas sales margin per unit of gas consumption during the year to arrive at the estimated impact on operating results of combined variations from normal temperatures and normalized gas consumption.

Reportable Business Segments

  ��   The Company is required to disclose information regarding its reportable business segments. Business segments that do not exceed the quantitative thresholds required to be reportable business segments are combined and included with the Company’s corporate division in a category the Company refers to as “Corporate and Other.” The Company reports one reportable business segment: Gas Distribution. The operating results of this business segment are discussed on the following pages. There is also a discussion of the results for Corporate and Other. The Company evaluates the performance of its business segments based on operating income. Operating income does not include income taxes, interest expense, discontinued operations, or other non-operating income and expense items. A review of the non-operating items follows the Gas Distribution and Corporate and Other discussions. The business segment discussions should be read in conjunction with Item 1 of this Form 10-K, which provides information regarding competition and other business matters. Refer to Note 11 of the Notes to the Consolidated Financial Statements in Item 8 of this Form 10-K for further information regarding business segments and a summary of business segment financial information.

Gas Distribution Business Segment

     Gas Sales Revenue. The Company’s gas sales revenue was $569.1 million, $463.4 million and $427.9 million for 2005, 2004 and 2003, respectively. The most significant factor causing the change in gas sales revenue fromyear-to-year is the change in the cost of gas sold. A significant portion of the Company’s cost of gas sold is accounted for by the Company’s GCR pricing mechanisms, which allow for the adjustment of rates charged to customers to reflect increases and decreases in the cost of gas purchased by the Company. Under these mechanisms, customers are charged rates that allow the Company to recoup its cost of gas purchased for sale to customers, subject, in the Company’s Michigan service territory regulated by the MPSC, to a review by the MPSC of the Company’s GCR gas purchase plan and the reasonableness of actual purchases and procurement practices. In Alaska, gas supply contracts are reviewed by the RCA at the time the Company enters into those contracts. As a result of the use of these mechanisms, in the absence of regulatory disallowances, for any increase or decrease in cost of gas sold, there is a corresponding increase or decrease in gas sales revenue. Refer to the caption “Cost of Gas, Gas Charges Recoverable from Customers,

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and Amounts Payable to Customers” in Note 1 of the Notes to the Consolidated Financial Statements in Item 8 of this Form 10-K for further information on cost of gas and the GCR mechanisms. Management generally evaluates changes in gas sales margin rather than gas sales revenue, due to the fluctuations caused by market-driven changes in cost of gas sold. Please refer to the gas sales margin section below for a detailed variance analysis.

		Years Ended December 31,
		2005			2004			2003
		($ in thousands)
Gas sales revenues		$	569,136		$	463,356		$	427,936
Cost of gas sold			443,860			346,241			308,919
	Gas sales margin	$	125,276		$	117,115		$	119,017
Gas transportation revenue			29,142			29,071			27,737
Other operating revenue			8,037			5,822			7,216
		$	162,455		$	152,008		$	153,970
Operations and maintenance			66,626			60,779			58,935
Depreciation and amortization			26,825			25,925			25,528
Property and other taxes			11,040			12,544			10,285
Operating income		$	57,964		$	52,760		$	59,222
Volumes of gas sold (MMcf)			64,723			66,165			67,272
Volumes of gas transported (MMcf)			55,709			56,619			51,358
Number of customers at year end			409,462			398,225			390,677
Average number of customers
	Gas sales customers		401,317			391,495			384,459
	Transportation customers		1,638			1,540			1,481
			402,955			393,035			385,940
Degree Days
	Alaska		9,572			9,573			9,384
	Michigan		6,689			6,726			7,063
Percent colder (warmer) than normal
	Alaska		(5.7	)%		(6.0	)%		(8.0	)%
	Michigan		(0.1	)%		(0.3	)%		4.7	%

      The amounts in the above table include intercompany transactions.

     Gas Sales Margin. The Company’s gas sales margin is derived primarily from customer service fees and consumption-based distribution fees. The customer service fees are fixed amounts charged to customers each month. Distribution fees vary each month because they are based on the volume of gas consumed by customers. There are four primary factors that have historically impacted gas sales margin and may impact future gas sales margin. These factors are changes in: (i) customer gas consumption; (ii) the number of gas sales customers; (iii) LAUF gas; and (iv) customer rates, including gas cost savings. In addition to these recurring factors, the Company sold excess gas to a third-party gas supplier in 2005, which also increased gas sales margin for 2005 by approximately $1.4 million.

      Changes in customer gas consumption from one year to another have historically been attributable primarily to the impact of changes in temperatures between periods. However, in recent years, other factors (including conservation by customers, the increasing use of more energy efficient gas furnaces and appliances, the addition of new energy efficient homes to the Company’s gas distribution system and the price of natural gas) have contributed more significantly than in the past to changes in customer gas consumption. A decrease in customer gas consumption reduced gas sales margin for 2005 by approximately $3.6 million, when

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compared to 2004. During 2005, customer gas consumption was lower than expected, given that temperatures during 2005 were similar to temperatures during 2004. The Company believes the decrease in gas consumption was due in large part to conservation prompted by the increased cost of natural gas. Refer to the discussion in Management’s Discussion and Analysis under the caption “The Impact of Higher Natural Gas Prices.” A decrease in customer gas consumption reduced gas sales margin for 2004 by approximately $2.3 million, when compared to 2003.

      The average number of gas sales customers in Michigan and Alaska combined (excluding customers acquired in the acquisition of Peninsular Gas) has increased by an average of 2.0% annually during the past three years. During 2005, Company’s average number of gas sales customers in Michigan and Alaska combined (excluding Peninsular Gas customers) increased by 7,653 or 1.9% when compared to 2004. During 2004, the Company’s average number of gas sales customers increased by 7,095 or 1.8% when compared to 2003. Customer additions increased gas sales margin for 2005 by approximately $2.5 million, when compared to 2004. Customer additions increased gas sales margin for 2004 by approximately $2.1 million, when compared to 2003. Customers added to the Company’s Michigan operation as a result of the acquisition of Peninsular Gas contributed $0.5 million to gas sales margin for 2005.

      LAUF gas is a term used in the natural gas distribution industry to refer to the difference between the gas that is measured and injected into the Company’s gas distribution system and the amount of gas measured at customer meters. Typically, there is more gas injected into a gas utility’s distribution system than is actually measured as sold or transported at customer meters. There are a number of reasons for this LAUF gas, including measurement errors and leaks. The annual LAUF gas volumes in Michigan have ranged from 0.5% to 1.4% of total gas volumes sold and transported in Michigan over the last ten years. An increase in LAUF gas expense decreased gas sales margin for 2005 by approximately $0.1 million, when compared to 2004. An increase in LAUF gas expense decreased gas sales margin for 2004 by approximately $1.0 million, when compared to 2003. The cost of LAUF gas is affected by the underlying commodity cost and rate mechanisms employed to price LAUF gas volumes and recover this cost from customers. Refer to the discussion in Management’s Discussion and Analysis under the caption “The Impact of Higher Natural Gas Prices,” for more information.

      The remainder of the change in gas sales margin from 2004 to 2005, an increase of $7.5 million, was due primarily to changes in rates and gas cost savings, as well as other miscellaneous factors. These same items also contributed to the remainder of the change in gas sales margin from 2003 to 2004, a decrease of $0.7 million. There was an increase in customer rates effective in March 2005, for MPSC-regulated customers. The rate increase for MPSC-regulated customers was the result of a settlement agreement reached with the MPSC. The CCBC approved new rates for CCBC-regulated customers, effective in April 2005, and the use of a GCR pricing mechanism, effective in April 2005. During 2003, 2004 and the first three months of 2005, the Company’s service area regulated by the CCBC was not operating under a GCR pricing mechanism and certain gas cost savings allowed under the terms of a gas supply and management agreement (which expired March 31, 2005) were retained by the Company. The gas cost savings realized under the agreement varied from year to year. For information on new rates and rate cases filed by the Company, refer to Note 2 of the Notes to the Consolidated Financial Statements in Item 8 of this Form 10-K. For further information regarding the Company’s natural gas supply and management agreements, GCR pricing mechanisms and gas cost savings, refer to the caption “Cost of Gas, Gas Charges Recoverable from Customers, and Amounts Payable to Customers” in Note 1 of the Notes to the Consolidated Financial Statements in Item 8 of this Form 10-K.

     Gas Transportation Revenue. The Company provides gas transportation services to customers who typically consume large volumes of natural gas. These customers purchase their natural gas directly from third-party suppliers. The natural gas purchased by customers from third-party suppliers is then transported on the Company’s gas distribution system to the customers. There was a $0.1 million increase in gas transportation revenue in 2005, when compared to 2004. The increase was primarily due to higher rates and volumes to industrial customers and an increase in transportation volumes to commercial customers, partially offset by a decrease in transportation volumes to power plants. There was a $1.3 million increase in gas transportation revenue in 2004, when compared to 2003. The primary reasons for the increase were increases

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in transportation volumes and rates for commercial transport customers, as well as an increase in transportation volumes for industrial and power plant transport customers.

      One of the Company’s Alaska service area industrial transportation customers, a fertilizer manufacturer, has publicly announced that it has experienced difficulty in securing sufficient natural gas supplies at an appropriate price to continue operating in the future. The customer has indicated that it has secured sufficient natural gas supplies to operate at a reduced rate through October 2006, but currently does not have sufficient natural gas under contract at an appropriate price to operate after that date. Transportation revenues to this customer totaled $2.0 million in 2004 and $2.0 million in 2005. Based upon volumes transported during 2005 and estimates provided by the customer, transportation revenues to this facility are expected to total $1.4 million in 2006. The Company cannot predict the likely pattern of future operations at this plant, including whether the plant will ultimately close.

     Other Operating Revenue. Increases in miscellaneous customer revenues and pipeline management revenues are the primary reasons for changes in other operating revenue during the past three years. In addition, a scheduled fee increase and aone-time settlement related to one of the Company’s large pipeline capacity contracts also contributed to the increase in other operating revenue in 2005. The miscellaneous customer revenues include various service fees and late payment fees charged to customers. An increase in these fees from 2004 to 2005 increased other operating revenue for 2005 by approximately $1.0 million. An increase in miscellaneous customer fees from 2003 to 2004 increased other operating revenue for 2004 by approximately $1.2 million.

      The pipeline management revenue is earned by NORSTAR. These revenues increased approximately $0.4 million in 2005, when compared to 2004, because of revenues earned from NORSTAR’s management of a pipeline construction project performed during 2005. Pipeline management revenue for 2004 decreased approximately $2.6 million from 2003 because NORSTAR was only performing routine pipeline management work and did not have a large management project similar to a project NORSTAR managed in 2003.

     Operations and Maintenance Expenses. For the year 2005, operations and maintenance (“O&M”) expenses increased by $5.8 million when compared to 2004. During 2004, O&M expenses increased by $1.8 million when compared to 2003. The changes in operating expenses over the past three years resulted from four primary factors: (i) employee benefit costs; (ii) professional fees; (iii) commercial insurance and claims costs; and (iv) uncollectible customer accounts.

      Employee benefit costs primarily include pension expense, medical coverage expense (including retiree medical coverage), and incentive compensation. For 2005, employee benefit costs increased by approximately $2.6 million. Approximately 66% of this increase was due to increased pension expense while much of the remainder of the increase was due to an increase in incentive compensation. For 2004, employee benefit costs decreased by approximately $0.9 million. The decrease for 2004 was a result of a $1.6 million decrease in medical coverage costs partially offset by increases in other employee benefits. The decrease in medical coverage costs in 2004 was primarily due to plan modifications that required employees and retirees to pay for a larger portion of their medical coverage costs and a decrease in retiree medical expense due to the provisions of the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (“Medicare Act”). For more information on the Medicare Act, refer to Note 8 of the Notes to the Consolidated Financial Statements in Item 8 of this Form 10-K.

      Professional fees (consisting primarily of accounting and legal fees) for 2005 were essentially unchanged from 2004 levels, but professional fees for 2004 increased by approximately $2.3 million, when compared to 2003. The increase in the amount of professional fees in 2004 and continued level in 2005 were due in large part to the increased level of costs to comply with the Sarbanes-Oxley Act of 2002.

      Commercial insurance and claims costs decreased by approximately $0.4 million for 2005, when compared to 2004. For 2004, commercial insurance and claims costs increased by approximately $0.7 million, when compared to 2003. Commercial insurance costs have increased significantly over the past few years as a result of the September 11, 2001 attack on the U.S., which has caused increases in liability insurance costs, and recent corporate financial wrongdoing by other large companies, which has increased director and officer

36

liability insurance costs. The Company had previously been shielded from these increases due to a three-year fixed premium general liability policy, which expired in 2003, and a fixed-premium excess liability policy, which expired in 2004.

      Uncollectible customer accounts increased by approximately $0.4 million in 2005, when compared to 2004. By comparison, during 2004, uncollectible customer accounts decreased by approximately $0.7 million, when compared to 2003. The increase in 2005 was due in large part to a higher cost of gas in 2005, offset partially by increased collection efforts and collection programs initiated by the Company. The decrease in uncollectible customer accounts in 2004 was primarily due to a reduction in large customer bankruptcywrite-offs.

      The remaining increase in O&M expenses from 2003 to 2004, and from 2004 to 2005, was caused by increases in compensation expense, facilities expense (including building and office lease expense), customer collection expense and various other expenses due primarily to inflationary pressures on expenses and the increased cost of doing business.

      When expenses continue to increase as a result of inflation or other factors, the Company typically files base rate cases to recover the increased cost of doing business. Refer to Note 2 of the Notes to the Consolidated Financial Statements in Item 8 of this Form 10-K for information regarding recent rate case filings.

     Depreciation and Amortization. The addition of new customers to the Company’s gas distribution system typically requires expansion of the system. In addition, the Company has a replacement program to ensure that older sections of its distribution system are being upgraded and replaced, and the Company also typically upgrades and relocates parts of its system in connection with public works projects to improve roads and other public facilities. The increase in depreciation and amortization expense from year to year is due to depreciation on net additional property, plant and equipment placed in service as a result of expanding and upgrading the system.

     Property and Other Taxes. The Company’s property and other taxes have increased over the past three years. The increases are primarily attributed to property taxes. Each year the Company’s property taxes generally increase as a result of taxes on net additional property, plant and equipment placed in service as part of the expansion and upgrading of the Company’s gas distribution system. During 2004, the Company also incurred $1.4 million in additional property tax expense as a result of adjusting the amount it estimated it would recover from certain prior years property tax appeals. During 2005, the Company initiated settlement offers to all taxing jurisdictions involved with the property tax appeals. Numerous taxing jurisdictions have accepted the Company’s settlement offer and, as a result, the Company reduced its 2005 property tax expense by approximately $0.5 million. The Company intends to pursue further refunds in 2006, which is expected to reduce 2006 property tax expense. Refer to Note 13 of the Notes to the Consolidated Financial Statements in Item 8 of this Form 10-K for information about the property tax appeals.

     Regulatory, Environmental and Other Matters. For further information regarding regulatory matters and the application of the FASB’s Statement of Financial Accounting Standards (“SFAS”) 71, “Accounting for the Effects of Certain Types of Regulation,” refer to Note 2 of the Notes to the Consolidated Financial Statements in Item 8 of this Form 10-K, the “Critical Accounting Policies” section of Management’s Discussion and Analysis and the Rates and Regulation section in Item 1 of this Form 10-K. For information regarding environmental matters and property tax litigation, refer to Note 13 of the Notes to the Consolidated Financial Statements in Item 8 of this Form 10-K. Refer to the section titled “Gas Distribution Business Segment” in Item 1 of this Form 10-K for information on competition in this business segment.

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Corporate and Other

	Years Ended December 31,
	2005		2004			2003
	(In thousands)
Operating revenues	$	16,379	$	17,152		$	17,220
Operating expenses		14,839		24,427			15,745
Operating income (loss)	$	1,540	$	(7,275	)	$	1,475

      The amounts in the above table include intercompany transactions.

     Operating Revenues. The Company’s businesses that are part of Corporate and Other, reported operating revenues of $16.4 million for 2005 and $17.2 million for both 2004 and 2003. The $0.8 million decrease for 2005 when compared to 2004 was due primarily to a decrease in IT service revenues. IT revenues have decreased because the Company generally has not been renewing contracts with non-affiliated customers due to ongoing efforts to focus the IT operations primarily on the Company’s IT needs. This includes in 2006, the expected implementation of a new Customer Information System and related system changes and upgrades.

     Operating Income. Corporate and Other reported operating income of $1.5 million for 2005, compared to an operating loss of $7.3 million for 2004 and operating income of $1.5 million for 2003. The 2005 results improved when compared to the 2004 results due in large part to $8.4 million in costs associated with the termination of the sale of the Company’s APC subsidiary included in the 2004 results. Also contributing to the improved results for 2005 were decreases in depreciation, IT and other miscellaneous expenses. The primary cause of the decrease in 2004, when compared to 2003, was the $8.4 million in costs associated with the termination of the sale of the Company’s APC subsidiary. The remainder of the decrease for 2004, when compared to 2003, was due primarily to goodwill and fixed asset impairment charges of $0.4 million at the Company’s IT operations and an increase in corporate consulting and professional fees, partially offset by a $0.3 million decrease in depreciation.

Other Income and Deductions

	Years Ended December 31,
	2005			2004			2003
	(In thousands)
Interest expense	$	(43,058	)	$	(44,293	)	$	(39,685	)
Debt exchange and extinguishment costs		(1,456	)		—			(24,030	)
Other income		2,768			2,497			2,154
Total other income (deductions)	$	(41,746	)	$	(41,796	)	$	(61,561	)

     Interest Expense. Interest expense decreased by $1.2 million in 2005, when compared to 2004, and increased by $4.6 million in 2004, when compared to 2003. The 2005 decrease was primarily due to lower levels of long-term debt as a result of the redemption of $29.9 million of the Company’s senior notes in the second quarter of 2004 and the redemption of $10.3 million and $30.9 million of the Company’s 10.25% Subordinated Notes in April 2005 and September 2005, respectively.

      Contributing to the 2004 increase was the adoption during 2003 of SFAS 150, “Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity,” and FASB Interpretation No. 46, “Consolidation of Variable Interest Entities, an Interpretation of ARB No. 51” (“FIN 46”). Dividends on Trust Preferred Securities issued by the Company’s capital trusts and interest expense on the Company’s debt held by the capital trusts incurred after July 1, 2003, has been reflected in interest expense as a result of adopting these accounting standards. These changes account for $1.0 million of the increase in interest expense during 2004. For further information on SFAS 150 and other new accounting standards that affect the Trust Preferred Securities, refer to Note 4 of the Notes to the Consolidated Financial Statements in Item 8 of this Form 10-K. The remainder of the increase in interest expense for 2004 when compared to 2003 was

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primarily due to higher levels of long-term debt, an increase in financing fees related to the Company’s short-term bank credit facility and an increase in amortization of debt issuance costs due to the issuance of additional long-term debt in 2003, partially offset by lower levels of short-term bank borrowings. A larger portion of the Company’s outstanding debt during all of 2004 and half of 2003 was long-term debt, which had a higher rate of interest than the Company’s short-term debt.

      Refer to Note 4 of the Notes to the Consolidated Financial Statements in Item 8 of this Form 10-K for information regarding the issuance and retirement of debt and Trust Preferred Securities during the past three years.

     Debt Exchange and Extinguishment Costs. During 2005, in association with the Company redemption, at par, of certain of its long-term debt, the Company incurred a $1.5 million non-cash debt extinguishment charge in its Consolidated Statements of Operations. The $1.5 million charge represented the write-off of the unamortized debt issuance costs related to the debt. For 2003, the Company’s Consolidated Statements of Operations reflect $24 million of debt exchange and extinguishment costs. In May 2003, the Company completed a refinancing of certain of its long-term debt through the issuance of new senior unsecured notes and the exchange and repurchase of existing notes. In connection with the repurchase of existing notes, the Company paid approximately $24 million for make-whole premiums or similar items. For further information regarding the 2005 redemption and the 2003 refinancing, refer to Note 4 of the Notes to the Consolidated Financial Statements in Item 8 of this Form 10-K.

     Other Income. The $0.3 million increase in other income for 2005, when compared to 2004, was primarily due to higher interest income (including allowance for funds used during construction (“AFUDC”)), partially offset by a decrease in equity earnings from the Company’s investment in ERGSS. The $0.3 million increase in other income for 2004, when compared to 2003, was primarily due to higher equity earnings from the Company’s investment in ERGSS and an increase in AFUDC.

Income Taxes

      The change in income taxes, when comparing one year to another, is due primarily to changes in income before income taxes and minority interest. However, in 2004, the Company made a change in estimate of its prior years state income taxes, which resulted in an additional income tax benefit of approximately $2.2 million. Refer to Note 3 of the Notes to the Consolidated Financial Statements in Item 8 of this Form 10-K for information on current and deferred income tax expense, deferred tax assets and liabilities, and recent net operating losses for tax purposes.

Minority Interest — Dividends on Company-Obligated Mandatorily Redeemable Trust Preferred Securities of Subsidiaries Holding Solely Debt Securities of Semco Energy, Inc., Net of Income Tax Benefit

      As discussed in the “Interest Expense” section, dividends on trust preferred securities incurred after July 1, 2003, were reflected in interest expense rather than in minority interest. This change accounts for the decrease in dividends on trust preferred securities in 2004, when compared to 2003. In addition, the retirement of approximately $101 million of trust preferred securities in August 2003 also contributed to the decrease in dividends on trust preferred securities. For further information on the retirement of the trust preferred securities, see Note 4 of the Notes to the Consolidated Financial Statements in Item 8 of this Form 10-K.

Discontinued Operations

      Substantially all the operating assets of the Company’s construction services business were sold in September 2004. The Company has accounted for this business as a discontinued operation and, accordingly, the operating results and the loss on the disposal of this business are segregated and reported as discontinued operations in the Consolidated Statements of Operations. During 2005, the Company recorded additional income related to its discontinued construction services business as a result of a settlement of litigation. For additional information, including a component breakdown of operating results reflected in discontinued operations, refer to Note 14 of the Notes to the Consolidated Financial Statements in Item 8 of this Form 10-K.

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Dividends and Repurchase Premium on Convertible Preference Stock

      The Company issued CPS in the first and second quarters of 2004. These securities and thepaid-in-kind, non-cash dividends on them are described in Note 4 of the Notes to the Consolidated Financial Statements. These securities were redeemed in March 2005. Dividend expense for the CPS amounted to $0.9 million and $3.2 million for the years ending December 31, 2005, and 2004, respectively. The Company’s Consolidated Statements of Operations for 2005 also included an $8.2 million premium associated with the repurchase of the CPS in March 2005.

Dividends on Convertible Cumulative Preferred Stock

      The Company issued the Preferred Stock in the first quarter of 2005. The Preferred Stock and the cash dividends on the Preferred Stock are described in Note 4 of the Notes to the Consolidated Financial Statements. Dividend expense for the Preferred Stock amounted to $3.0 million for the year ended December 31, 2005.

Liquidity and Capital Resources

     Cash Flows Used For Investing. The Company’s Gas Distribution Business is capital intensive and a substantial amount of cash is spent annually on investments in property, plant and equipment. The following table identifies capital investments for the past three years:

		Years Ended December 31,
		2005		2004		2003
		(In thousands)
Capital investments
	Property additions — gas distribution	$	38,739	$	37,924	$	28,323
	Property additions — corporate and other		1,417		988		1,843
	Business acquisition, net of cash acquired		3,076		—		—
		$	43,232	$	38,912	$	30,166

      Property additions for the Gas Distribution Business increased $0.8 million during 2005, when compared to 2004. Property additions for the Gas Distribution Business increased $9.6 million during 2004, when compared to 2003. The primary reason for the increase in property additions in 2005 and 2004, when compared to 2003, was a higher amount of spending on computer systems and other special projects.

      Property additions for Corporate and Other increased $0.4 million during 2005, when compared to 2004. The increase was primarily due to leasehold improvement costs incurred for the Company’s leased office facilities. Property additions for Corporate and Other decreased $0.9 million during 2004, when compared to 2003. The primary reason for the decrease was the sale of the Company’s construction services business.

      In addition, the Company acquired substantially all of the assets and certain liabilities of Peninsular Gas on June 1, 2005. The Company paid approximately $2.8 million, net of cash acquired, for this acquisition in the second quarter of 2005 and an additional $0.3 million in the third quarter of 2005. For further information, refer to Note 14 of the Notes to the Consolidated Financial Statements in Item 8 of this Form 10-K.

      In 2006, the Company plans to spend approximately $42 million on property additions. The Company may also, as part of the execution of its strategic plan, make acquisitions of, or investments in, other businesses.

     Cash Flows Provided by Operations. The Company’s net cash provided by (used for) operating activities totaled $28.8 million in 2005, $40.2 million in 2004 and $(12.5) million in 2003. The change in operating cash flows is influenced by changes in the level and cost of gas in underground storage, changes in accounts receivable and accounts payable and other working capital changes. The changes in these accounts are largely the result of the timing of cash receipts and payments. The change in cash provided by operating activities is also impacted by changes in the operating results of the Company’s businesses.

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      The Company’s largest use of cash is for the purchase of natural gas for its customers. Generally, gas is injected into storage during the months of April through October and withdrawn for sale from November through March. In prior years, the Company also used significant amounts of short-term borrowings to finance natural gas purchases for storage during the non-heating season. However, in 2003, the Company reduced its dependence on short-term borrowings for its seasonal storage gas purchases by utilizing part of the proceeds from the issuance of additional long-term debt to pay down its short-term credit facility. An increase in the price of natural gas during the last half of 2005 required the Company to again utilize significant amounts of short-term borrowings for its natural gas purchases.

      The Company’s credit ratings were lowered over the past few years by both Moody’s Investors Service and Standard & Poor’s. As a result of these events and other circumstances, the interstate pipelines the Company utilizes require prepayment for their services. In addition, certain of the Company’s gas suppliers may require the Company to prepay or provide letters of credit for gas purchases over and above the levels of credit they may have extended the Company. These prepayment requirements shortened the Company’s accounts payable cycle during 2003. The improvement in cash flows from operating activities in 2004 was due primarily to the easing of these credit restrictions put in place during 2003 by certain of the gas suppliers utilized by the Company. This lengthened the Company’s accounts payable cycle in 2004 when compared to 2003. The other primary factor contributing to the increase in operating cash flows in 2004 was a smaller increase in the price of gas during 2004 when compared to 2003.

      The decrease in cash flows from operating activities during 2005 was due primarily to a substantial increase in the market price of natural gas purchased in the last half of 2005. As a result, the cost of the Company’s gas in underground storage at December 31, 2005, was approximately $29 million higher than it was at December 31, 2004. The higher cost of gas was also reflected in customer rates, which caused a significant increase in accounts receivable from December 31, 2004, to December 31, 2005. The impact of higher gas prices on operating cash flow was partially offset by more favorable credit terms the Company obtained from various gas suppliers during 2005. For additional information concerning the recent increases in natural gas prices, refer to the discussion in Management’s Discussion and Analysis, under the caption “The Impact of Higher Natural Gas Prices”.

     Cash Flows Provided by Financing. The Company’s net cash provided by (used for) financing activities totaled $15.8 million, $(28.5) million and $40.9 million in 2005, 2004 and 2003, respectively.

		Years Ended December 31,
		2005			2004			2003
		(In thousands)
Cash provided by (used for) financing activities
	Issuance of common stock and common stock warrants, net of expenses	$	29,918		$	2,500		$	3,329
	Issuance of convertible cumulative preferred stock, net of expenses		66,302			—			—
	Issuance of convertible preference stock, net of expenses		—			45,590			—
	Repurchase of convertible preference stock and common stock warrants		(60,000	)		—			—
	Issuance (repayment) of notes payable and payment of related expenses		38,983			(43,074	)		(39,800	)
	Issuance of long-term debt, net of redemptions		(56,364	)		(30,132	)		109,622
	Debt exchange and extinguishment costs		—			—			(24,030	)
	Payment of dividends on convertible cumulative preferred stock		(2,333	)		—			—
	Payment of dividends on common stock		—			(4,221	)		(8,235	)
	Change in book overdrafts included in current liabilities		(690	)		883			—
		$	15,816		$	(28,454	)	$	40,886

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      During 2004, the Company issued, through a private placement to K-1, $50 million of CPS and Warrants to purchase 905,565 shares of the Company’s Common Stock. The net proceeds (proceeds less issuance costs) from the issuance amounted to approximately $46.3 million and were used to pay down short-term debt and invest temporarily in cash equivalents. In June 2004, a portion of the proceeds invested temporarily in cash equivalents was used to redeem all $29.9 million of its outstanding 8% Senior Notes Due 2010 at par. The Company paid stock dividends on the CPS of 1,766 additional shares of CPS during 2004. For further information, refer to Note 4 of the Notes to the Consolidated Financial Statements.

      During the first quarter of 2005, the Company repurchased all of the CPS (52,543 shares) and Warrants (905,565 Warrants) held by K-1. The aggregate purchase price for the CPS and Warrants was $60 million. During the first quarter of 2005, the Company also completed the sale of 350,000 shares of Preferred Stock. The gross proceeds from this offering were approximately $70 million, of which $60 million was used to fund the repurchase of CPS and Warrants from K-1. The remaining proceeds were used to redeem $10.3 million principal amount of the Company’s 10.25% Subordinated Notes held by SEMCO Capital Trust I. The Trust, in turn, used the proceeds to redeem 400,000 Trust Preferred Securities and 12,371 common securities on April 29, 2005.

      During the third quarter of 2005, the Company completed an offering of 4,945,000 shares of Common Stock. The proceeds from this offering were used to redeem the remaining $30.9 million of the 10.25% Subordinated Notes held by the Trust. The Trust, in turn, used the proceeds from the redemption of the 10.25% Subordinated Notes to redeem the remaining 1.2 million Trust Preferred Securities and 37,114 common securities on September 14, 2005.

      For further information regarding these transactions, refer to Note 4 of the Notes to the Consolidated Financial Statements in Item 8 of this Form 10-K.

      In December of 2003, the Company issued an aggregate of $50 million of senior unsecured notes with a premium of $2.1 million. The proceeds from this issuance were used to repay indebtedness under the Company’s then-existing bank credit facility.

      In May of 2003, the Company completed an offering of an aggregate of $300 million of senior unsecured notes. The Company used approximately $92.3 million of the new notes in an exchange for other outstanding debt of the Company. For further information regarding the use of the remaining proceeds from the $300 million offering, which included the retirement of other debt of the Company and payment of debt extinguishment costs, see Note 4 of the Notes to the Consolidated Financial Statements in Item 8 of this Form 10-K.

      In June 2004, the Company suspended the quarterly cash dividend on the Company’s Common Stock, with the objective of supplementing free cash flow. In addition, the decision reflects the Company’s desire to retain cash in order to strengthen its balance sheet, enhance financial flexibility and to be better positioned to grow the Company’s Gas Distribution Business in the future. Cash dividends paid per share for common shareholders were $0.15, and $0.40 in 2004, and 2003, respectively.

     Non-Cash Financing Activities. For information regarding non-cash financing activities, refer to the caption “Statements of Cash Flows” in Note 1 of the Notes to the Consolidated Financial Statements in Item 8 of this Form 10-K.

     Pension Plans and Other Post Retirement Benefits. The Company has defined-benefit pension plans (“Pension Plans”) that cover approximately 99% of the Company’s employees. During 2005, the Company contributed $5.7 million to the Pension Plans. The Company anticipates that the annual contribution to the Pension Plans in 2006 will be approximately $5.4 million. The funding of such contributions will come from amounts collected in Gas Distribution Business rates or through short-term borrowings.

      The Company provides certain medical and prescription drug benefits to approximately 300 eligible retired employees and their surviving spouses under postretirement benefit plans (“Postretirement Plans). During 2005, the Company paid approximately $1.7 million to cover the costs of the Postretirement Plans out of its corporate assets. The Company anticipates that the annual payments to cover the costs of the

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Postretirement Plans in 2006 will be approximately $1.7 million and will be paid out of corporate assets or its funded postretirement benefit plans.

     Future Financing. In general, the Company funds its capital expenditure program and dividend payments with operating cash flows and the utilization of its Bank Credit Agreement. When appropriate, the Company will refinance its short-term debt with long-term debt, Common Stock issuances or otherlong-term financing instruments. The Company is currently evaluating the refinancing potential for one of its debt obligations. Approximately $59.6 million of 8% senior notes that are due June 30, 2016 (“8% Senior Notes”) will become callable at par on June 30, 2006. The Company is considering the merits of the redemption at par of the 8% Senior Notes on or after the first call date as well as the issuance of a similar amount and similar term debt instrument. Any previously incurred debt issuance costs that have not been amortized up to the date of redemption would be expensed at the time of the redemption. At December 31, 2005, the unamortized debt issuance costs related to the 8% Senior Notes amounted to $1.1 million.

      The Company’s capital structure at December 31, 2005, consisted of approximately 66.7% total debt (including current maturities and notes payable), 8.5% preferred stock and 24.8% common equity. The Company continues to assess its overall liquidity and capital structure, with a view to migrating over time to a capital structure which is consistent with that of an investment grade company. One of the Company’s primary goals is to increase equity as a percentage of total capital while reducing the Company’s overall debt to total capital ratio. Although there are no current specific plans to issue equity or reduce long-term debt in 2006, the Company will continue to look for and, as appropriate, take advantage of market opportunities to do so as they arise.

      On June 14, 2005, a universal shelf registration statement on Form S-3 (“June 2005 Registration Statement”) filed by the Company with the SEC became effective. The Company registered an aggregate of $150 million of various securities under the June 2005 Registration Statement. Subsequent to the effectiveness of the June 2005 Registration Statement, the Company completed a Common Stock offering of $31.3 million, leaving $118.7 million of securities available for possible future issuances of Common Stock, preferred stock, trust preferred securities and long-term debt. At the present time, the Company does not meet the requirements under its indentures to issue additional senior notes but the Company is permitted to refinance maturing debt. Long-term debt of the Company scheduled to mature during the next five years includes $150 million of 7.125% notes due in 2008, $5 million of 6.40% notes due in 2008 and $30 million of 6.49% notes due in 2009.

      In September 2005, the Company entered into the Bank Credit Agreement for $120 million, which expires on September 15, 2008. The Bank Credit Agreement amends and restates the Company’s previous short-term bank credit facility, which consisted of a $60 million multi-year revolving facility and a $40.8 million364-day facility, both of which were due to expire on September 23, 2005. Interest under the terms of the Bank Credit Agreement is at variable rates, which are based on LIBOR or prime lending rates, plus applicable margins. At December 31, 2005, the Company was utilizing $95.7 million of the borrowing capacity available under the Bank Credit Agreement, leaving approximately $24.3 million of the borrowing capacity unused. The $95.7 million of capacity being used consisted of $16.8 million of outstanding letters of credit and $78.9 million of outstanding borrowings. Refer to Note 5 of the Notes to the Consolidated Financial Statements in Part II, Item 8 of this Form 10-K for additional information regarding the Bank Credit Agreement, including a description of the covenants contained therein.

      The Company’s Gas Distribution Business is seasonal in nature. During the winter heating season, higher volumes of gas are sold, resulting in peak profitability during the fourth and first quarters of the year. The Company’s cash flow and its corresponding use of its Bank Credit Agreement typically also follow a seasonal pattern. The Company uses funds available under the Bank Credit Agreement to finance, on a short-term basis, the variability and seasonality of its operating cash flow and working capital requirements. Typically, as the Company collects cash from winter heating sales in the latter part of the first quarter and the second quarter, it will pay down the borrowings under the Bank Credit Agreement. During the summer months, it will reduce its short-term borrowings under the Bank Credit Agreement, and possibly build up sufficient cash to enable it to enter into short-term investments. As gas is purchased throughout the summer and injected into

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storage in preparation for the winter heating season and the Company completes its annual construction and capital expenditure program, the Company expects to incur borrowings under the Bank Credit Agreement. Such borrowings typically begin to occur prior to the end of the third quarter and intensify, such that the maximum short-term borrowings occur around the end of the year. This borrowing pattern is affected by numerous items including the credit terms under which the Company purchases natural gas for sale to customers and its GCR factors in various jurisdictions. As winter sales occur and gas sales revenues are billed and collected, the Company again begins to reduce its short-term borrowings in the first quarter. Refer to the discussion in Management’s Discussion and Analysis, under the caption “The Impact of Higher Natural Gas Prices,” for information regarding additional working capital requirements that have resulted from recent increases in the price of natural gas.

     Business Development Initiatives. From time to time, in pursuing its growth strategy, the Company considers, among other things, acquisitions of or investments in local distribution, pipeline, and gas storage businesses and assets. These acquisitions and investments are typically considered pursuant to confidentiality agreements, which, among other things, allow the exchange of data subject to non-disclosure requirements (usually barring the disclosure or misuse of such data and requiring that the fact of discussions of a possible acquisition or investment be kept secret). The Company generally will not make any public announcement of such activities until definitive agreements with respect thereto have been signed.

     Ratio of Earnings to Fixed Charges and Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividends. The Company’s ratio of earnings to fixed charges, as defined under Item 503 of SEC regulation S-K, was 1.40 for 2005, 1.06 for 2004 and less than aone-to-one coverage for 2003. The amount of earnings that would be required to attain a ratio ofone-to-one for 2003 was approximately $8.0 million. The Company’s ratio of earnings to combined fixed charges and preferred stock dividends, as defined under Item 503 of SEC regulation S-K was less than aone-to-one coverage for 2005, 2004 and 2003. The amount of earnings that would be required to attain a ratio of one-to-one for 2005, 2004 and 2003 was approximately $0.9 million, $3.4 million and $8.0 million, respectively.

     Off-Balance Sheet Arrangements. The Company does not have any off-balance sheet financing arrangements as defined in Item 303(a)(4) of Regulation S-K.

     Guarantees. The Company has letters of credit that are required to be disclosed under the provisions of Financial Accounting Standards Board Interpretation No. 45, “Guarantors Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others.” For information on these letters of credit, refer to Note 13 of the Notes to the Consolidated Financial Statements in Item 8 of this Form 10-K.

     Contractual Obligations and Commercial Commitments. Summarized below are the contractual obligations and commercial commitments of the Company as of December 31, 2005:

	Payments Due by Period
													2011
Contractual Obligations	Total		2006		2007		2008		2009		2010		and Beyond
					(In millions)
Long-term debt obligations	$	454.6	$	—	$	—	$	155.0	$	30.0	$	—	$	269.6
Unconditional gas purchase and gas transportation obligations		228.9		168.7		26.6		19.4		11.6		2.6		—
Operating lease obligations		15.2		1.9		1.8		1.9		1.9		1.9		5.8
Total contractual obligations	$	698.7	$	170.6	$	28.4	$	176.3	$	43.5	$	4.5	$	275.4

	Amount of Commitment Expiration per Period
													2011
Commercial Commitments	Total		2006		2007		2008		2009		2010		and Beyond
Bank credit facility	$	120.0	$	—	$	—	$	120.0	$	—	$	—	$	—

44

     Other Commitments and Contingencies. For information about other commitments and contingencies, refer to Note 13 of the Notes to the Consolidated Financial Statements in Item 8 of this Form 10-K.

Market Risk Information

      The Company’s primary market risk arises from fluctuations in natural gas and propane prices and interest rates. The Company’s exposure to commodity price risk arises from changes in natural gas and propane prices throughout the United States and in eastern Canada, where the Company conducts sales and purchase transactions. The Company does not currently use financial derivative instruments (such as swaps, collars or futures) to manage its exposure to commodity price risk. A significant portion of the natural gas requirements of the Company’s Michigan gas distribution operations are covered under third-party supply arrangements and the GCR mechanism through which commodity costs are paid by customers. ENSTAR’s natural gas requirements are primarily covered by a number of RCA-approved long-term supply arrangements and the GCR mechanism through which commodity costs are paid by customers. For further information on how these agreements and mechanisms reduce the Company’s exposure to commodity price risk, see the caption “Cost of Gas, Gas Charges Recoverable from Customers, and Amounts Payable to Customers” in Note 1 of the Notes to the Consolidated Financial Statements in Item 8 of this Form 10-K.

      The Company is also subject to interest rate risk in connection with the issuance of variable and fixed-rate debt. In order to maintain its desired mix of fixed-rate and variable-rate debt, the Company may use interest rate swap agreements and exchange fixed and variable-rate interest payment obligations over the life of the agreements, without exchange of the underlying principal amounts. See Note 7 of the Notes to the Consolidated Financial Statements in Item 8 of this Form 10-K for additional information on interest rate swap agreements and how the Company accounts for its risk management activities.

      For information regarding the fair value of the Company’s financial instruments, refer to Note 6 of the Notes to the Consolidated Financial Statements in Item 8 of this Form 10-K. The following table provides information about the Company’s financial instruments that are sensitive to interest rate changes as of December 31, 2005:

		Principal Payments by Expected Maturity Date and Interest Rate Detail
															2011
															and
As of December 31, 2005		2006			2007		2008			2009			2010		Beyond			Total
		(In millions, except percentages)
Long-term debt
	Fixed rate	$	—		$	—	$	155.0		$	30.0		$	—	$	269.6		$	454.6
	Average interest rate		—			—		7.10	%		6.49	%		—		7.78	%		7.46	%
Bank Credit facility
	Variable rate(a)	$	120.0		$	—	$	—		$	—		$	—	$	—		$	120.0
	Average interest rate(b)		5.62	%		—		—			—			—		—			5.62	%

(a)	Amounts represent total credit available to the Company at December 31, 2005 rather than the actual amount outstanding at December 31, 2005.
(b)	The average interest rate reported for the variable rate bank credit facility is the average rate during the year ended December 31, 2005.

Impact of Inflation

      The cost of gas purchased by the Gas Distribution Business for sale to customers is recovered from customers through GCR pricing mechanisms. The GCR pricing mechanisms allow for the adjustment of rates charged to customers to reflect, in the absence of cost disallowances, increases and decreases in the cost of gas purchased by the Company. See the caption “Cost of Gas, Gas Charges Recoverable from Customers, and Amounts Payable to Customers” in Note 1 of the Notes to the Consolidated Financial Statements in Item 8 of this Form 10-K for more information on these mechanisms. Increases and decreases in customer rates

45

under the GCR pricing mechanisms generally occur annually but can occur more frequently in certain circumstances and occur monthly in the service area regulated by the CCBC. The price of natural gas increased substantially during the last half of 2005. For information regarding the impact of higher natural gas prices on the Company, refer to the risk factors in Item 1A and the caption “The Impact of Higher Natural Gas Prices” in Item 7 of this Form 10-K.

      Increases in other operating costs are recovered in MPSC-, CCBC- and RCA-approved rates, typically as a result of a base rate filing made by the Company. Recovering cost increases through this process may adversely affect the results of operations due to the time lag involved securing necessary rate approvals and the decisions made on the merits of the Company’s requests. The Company attempts to minimize the impact of inflation by controlling costs, increasing productivity and filing base rate cases on a timely basis.

Critical Accounting Policies

      The Company has prepared its Consolidated Financial Statements in conformity with accounting principles generally accepted in the U.S. The preparation of these financial statements requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results may differ from those estimates. In the event estimates or assumptions prove to be different from actual results, adjustments are made in subsequent periods to reflect more current information. The following is a summary of the Company’s most critical accounting policies, which are defined as those policies under which judgments or uncertainties could affect the application of those policies and materially different amounts could be reported under different conditions or using different assumptions. For a complete discussion of the Company’s significant accounting policies, refer to Note 1 of the Notes to the Consolidated Financial Statements in Item 8 of this Form 10-K.

     Rate Regulation. The Gas Distribution Business is subject to regulation. The regulatory matters associated with gas distribution customers located in the City of Battle Creek, Michigan, and surrounding communities are subject to the jurisdiction of the CCBC. The MPSC has jurisdiction over the regulatory matters related to the Company’s remaining Michigan customers. Regulatory matters for gas distribution customers in Alaska and APC are subject to the jurisdiction of the RCA. These regulatory bodies have jurisdiction over, among other things, rates, accounting procedures, and standards of service.

      The Gas Distribution Business has accounting policies, which conform to SFAS 71, “Accounting for the Effect of Certain Types of Regulation” and which are in accordance with the accounting requirements and ratemaking practices of the MPSC, CCBC and RCA. The application of these accounting policies allows the Company to defer expenses and income as regulatory assets and liabilities in the Consolidated Statements of Financial Position when it is probable that those expenses and income will be allowed in the rate-setting process in a period different from the period in which they would have been reflected in the Consolidated Statements of Operations by an unregulated business. These deferred regulatory assets and liabilities are then included in the Consolidated Statements of Operations in the periods in which the same amounts are reflected in rates. Management’s assessment of the probability of recovery or pass-through of regulatory assets and liabilities requires judgment and interpretation of laws and regulatory commission orders. If, for any reason, the Company ceases to meet the criteria for application of regulatory accounting treatment for all or part of its operations, the regulatory assets and liabilities related to those portions ceasing to meet such criteria would be eliminated from the Consolidated Statements of Financial Position and included in the Consolidated Statements of Operations for the period in which the discontinuance of regulatory accounting treatment occurs. Such amounts would be classified as extraordinary items.

     Goodwill. The Company evaluates its goodwill for impairment in accordance with SFAS 142, “Goodwill and Other Intangible Assets.” SFAS 142 requires that the Company perform impairment tests on its goodwill balance annually or at any time when events occur that could impact the value of the Company’s business segments. The Company’s determination of whether an impairment has occurred is based on an estimate of discounted cash flows attributable to the Company’s reporting units that have goodwill, as compared to the carrying value of those reporting units’ net assets. The Company must make long-term

46

forecasts of future revenues, expenses and capital expenditures related to the reporting unit in order to make the estimate of discounted cash flows. These forecasts require assumptions about future demand, future market conditions, regulatory developments and other factors. Significant and unanticipated changes to these assumptions could require a provision for impairment in a future period. If an impairment test of goodwill shows that the carrying amount of the goodwill is in excess of the fair value, a corresponding impairment loss would be recorded in the Consolidated Statements of Operations.

      The 2005 annual impairment tests were performed for the Company’s business segments and indicated that there was no impairment of goodwill for any of its business segments. The 2004 annual impairment tests were performed for the Company’s business segments and indicated that there was an impairment of goodwill at the Company’s IT services business. The 2003 annual impairment tests were performed for the Company’s business segments and indicated that there was an impairment of goodwill for the construction services business. For further information on these impairments, see Note 1 of the Notes to the Consolidated Financial Statements in Item 8 of this Form 10-K.

     Pensions and Other Postretirement Benefits. The Company accounts for pension costs and other postretirement benefit costs in accordance with the SFAS 87, “Employers’ Accounting for Pensions” and SFAS 106, “Employers’ Accounting for Postretirement Benefits Other Than Pensions,” respectively. These statements require liabilities to be recorded in the Consolidated Statements of Financial Position at the present value of these future obligations to employees net of any plan assets. The calculation of these liabilities and associated expenses require the expertise of actuaries and are subject to many assumptions, including life expectancies, present value discount rates, expected long-term rate of return on plan assets, rate of compensation increase and anticipated health care costs. The discount rate used by the Company is determined by reference to the CitiGroup pension discount curve, other long-term corporate bond measures and the expected cash flows of the plans. The duration of the securities underlying those indexes reasonably matches the expected timing of anticipated future benefit payments. The expected long-term rate of return on plan assets is established based on the Company’s expectations of asset returns for the investment mix in its plans (with some reliance on historical asset returns for the plans). The expected returns of various asset categories are blended to derive an appropriate long-term assumption.

      Any change in these assumptions can significantly change the liability and associated expenses recognized in any given year. For example, a one percentage point increase in anticipated health care costs each year would increase the accumulated retiree medical obligation as of December 31, 2005, by $5.7 million and the aggregate of the service and interest cost components of net periodic retiree medical costs for 2005, by $0.4 million. For further sensitivity analyses, refer to Note 8 of the Notes to the Consolidated Financial Statements in Item 8 of this Form 10-K.

New Accounting Standards

      In December 2004, the FASB issued SFAS 123-R (Revised 2004) — “Share-Based Payment.” In March 2005, the FASB issued Interpretation No. 47, Accounting for Conditional Asset Retirement Obligations. In May 2005, the FASB issued SFAS No. 154, “Accounting Changes and Error Corrections” Refer to the “New Accounting Standards” section of Note 1 of the Notes to the Consolidated Financial Statements in Item 8 of this Form 10-K for information on these new accounting standards.

47

Item 7A. Quantitative and Qualitative Disclosures About Market Risk

      For the information required pursuant to this item, refer to the section titled “Market Risk Information” in Item 7 of this Form 10-K.

Item 8. Financial Statements and Supplementary Data

      This item includes the following information in the order shown:

      Report of Independent Registered Public Accounting Firm

      Consolidated Statements of Operations

      Consolidated Statements of Financial Position

      Consolidated Statements of Cash Flows

      Consolidated Statements of Capitalization

      Consolidated Statements of Changes in Common Shareholders’ Equity

      Consolidated Statements of Comprehensive Income

      Notes to the Consolidated Financial Statements

      Financial Statement Schedule II — Consolidated Valuation and Qualifying Accounts

      All other financial statement schedules are omitted because they are not applicable or the required information is shown in the Consolidated Financial Statements or Notes thereto.

48

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of

SEMCO Energy, Inc.:

      We have completed integrated audits of SEMCO Energy, Inc.’s 2005 and 2004 consolidated financial statements and of its internal control over financial reporting as of December 31, 2005, and an audit of its 2003 consolidated financial statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Our opinions, based on our audits, are presented below.

Consolidated Financial Statements and Financial Statement Schedule

      In our opinion, the consolidated statements of financial position and capitalization and the related consolidated statements of operations, changes in common shareholders’ equity, comprehensive income and cash flows present fairly, in all material respects, the financial position of SEMCO Energy, Inc. and its subsidiaries at December 31, 2005 and 2004, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2005 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in Item 15(a)(2) presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit of financial statements includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

Internal Control over Financial Reporting

      Also, in our opinion, management’s assessment, included in Management’s Report on Internal Control Over Financial Reporting appearing under Item 9A, that the Company maintained effective internal control over financial reporting as of December 31, 2005 based onInternal Control — Integrated Frameworkissued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), is fairly stated, in all material respects, based on those criteria. Furthermore, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2005, based on criteria established inInternal Control — Integrated Frameworkissued by the COSO. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express opinions on management’s assessment and on the effectiveness of the Company’s internal control over financial reporting based on our audit. We conducted our audit of internal control over financial reporting in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. An audit of internal control over financial reporting includes obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we consider necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions.

      A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that,

49

in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

      Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ PricewaterhouseCoopers LLP

PricewaterhouseCoopers LLP

Detroit, Michigan

March 8, 2006

50

CONSOLIDATED STATEMENTS OF OPERATIONS

		Years Ended December 31,
		2005			2004			2003
		(In thousands, except per share
		amounts)
Operating Revenues
	Gas sales	$	569,136		$	463,356		$	427,936
	Gas transportation		29,142			29,071			27,737
	Other		16,824			15,909			17,282
			615,102			508,336			472,955
Operating expenses
	Cost of gas sold		443,860			346,241			308,919
	Operations and Maintenance		71,913			67,333			65,152
	Depreciation and amortization		28,224			27,578			27,448
	Property and other taxes		11,601			13,149			10,739
	Expenses related to terminated sale of subsidiary		—			8,398			—
	Goodwill impairment charge		—			152			—
			555,598			462,851			412,258
Operating income			59,504			45,485			60,697
Other income (deductions)
	Interest expense		(43,058	)		(44,293	)		(39,685	)
	Debt exchange and extinguishment costs		(1,456	)		—			(24,030	)
	Other		2,768			2,497			2,154
			(41,746	)		(41,796	)		(61,561	)
Income (loss) before income taxes and minority interest			17,758			3,689			(864	)
Income tax (expense) benefit			(6,021	)		467			80
Minority interest — dividends on company-obligated mandatorily redeemable trust preferred securities of subsidiaries holding solely debt securities of SEMCO Energy, Inc., net of income tax benefit of $0, $0 and $2,316			—			—			(4,300	)
Income (loss) from continuing operations			11,737			4,156			(5,084	)
Discontinued operations
	Income (loss) from construction services operations, net of income tax (expense) benefit of $(312), $1,782 and $7,362		538			(4,641	)		(24,871	)
	Loss on divestiture of construction services operations, net of income tax benefit of $0, $1,722 and $0		—			(4,698	)		—
Net income (loss)			12,275			(5,183	)		(29,955	)
Dividends on convertible cumulative preferred stock			2,994			—			—
Dividends and repurchase premium on convertible preference stock			9,112			3,203			—
Net income (loss) available to common shareholders		$	169		$	(8,386	)	$	(29,955	)
Earnings per share — basic
	Income (loss) from continuing operations	$	(0.01	)	$	0.03		$	(0.23	)
	Net income (loss) available to common shareholders	$	0.01		$	(0.30	)	$	(1.34	)
Earnings per share — diluted
	Income (loss) from continuing operations	$	(0.01	)	$	0.03		$	(0.23	)
	Net income (loss) available to common shareholders	$	0.01		$	(0.30	)	$	(1.34	)
Dividends declared per share		$	—		$	0.08		$	0.35
Average common shares outstanding — basic			30,408			28,263			22,297
Average common shares outstanding — diluted			30,408			28,296			22,297

The accompanying notes to the consolidated financial statements are an integral part of these statements.

51

CONSOLIDATED STATEMENTS OF FINANCIAL POSITION

		December 31,
		2005		2004
		(In thousands, except for
		number of shares and
		par value)
Current Assets
	Cash and cash equivalents	$	4,124	$	2,118
	Restricted cash		1,590		1,588
	Receivables, less allowances of $1,758 and $2,247		64,584		36,327
	Accrued revenue		71,615		54,285
	Gas in underground storage, at average cost		93,065		63,980
	Prepaid expenses		15,307		21,450
	Deferred income taxes		5,345		341
	Materials and supplies, at average cost		4,970		4,876
	Regulatory asset — gas charges recoverable from customers		971		137
	Other		1,114		1,266
			262,685		186,368
Property Plant and Equipment
	Gas distribution		735,052		697,079
	Corporate and other		39,879		39,607
			774,931		736,686
	Less accumulated depreciation		197,543		177,012
			577,388		559,674
Deferred Charges and Other Assets
	Goodwill		143,374		143,283
	Regulatory assets		12,602		12,062
	Unamortized debt expense		10,057		13,313
	Other		10,449		11,498
			176,482		180,156
Total Assets		$	1,016,555	$	926,198
Current Liabilities
	Current maturities of long-term debt	$	—	$	15,092
	Notes payable		78,900		39,300
	Accounts payable		64,557		29,254
	Customer advance payments		22,043		19,818
	Regulatory liability — amounts payable to customers		12,281		5,624
	Pension and other postretirement costs		7,100		4,300
	Accrued interest		4,616		4,508
	Other		8,806		9,187
			198,303		127,083
Deferred Credits and Other Liabilities
	Regulatory liabilities		59,214		57,442
	Deferred income taxes		30,715		20,758
	Customer advances for construction		17,263		15,887
	Pension and other postretirement costs		3,490		5,571
	Other		5,385		1,631
			116,067		101,289
Commitments and Contingencies (See Note 13)
Capitalization
	Long-term debt		441,659		483,335
	Convertible cumulative preferred stock, $1 par value, 500,000 shares authorized; 350,000 and 0 shares outstanding		66,526		—
	Series B convertible preference stock, $1 par value, 70,000 shares authorized; 0 and 51,766 shares outstanding		—		48,405
	Common shareholders’ equity		194,000		166,086
			702,185		697,826
Total Liabilities and Capitalization		$	1,016,555	$	926,198

The accompanying notes to the consolidated financial statements are an integral part of these statements.

52

CONSOLIDATED STATEMENTS OF CASH FLOWS

				Years Ended December 31,
				2005			2004			2003
				(In thousands)
Cash flow provided by (used for) operating activities
	Net income (loss)			$	12,275		$	(5,183	)	$	(29,955	)
	Adjustments to reconcile net income (loss) to net cash provided by (used for) operating activities:
		Depreciation and amortization			28,224			27,578			27,448
		Depreciation and amortization in discontinued operations			—			443			7,832
		Amortization of debt costs and debt basis adjustments included in interest expense			3,507			3,630			2,369
		Accumulated deferred income taxes and amortization of investment tax credits			4,955			(3,658	)		(10,848	)
		Non-cash impairment charges			—			152			20,474
		Non-cash share-based compensation			756			187			56
		Loss on divestiture of discontinued construction services business			—			6,420			—
		Debt exchange and extinguishment costs			1,456			—			24,030
		Changes in operating assets and liabilities and other, excluding the impact of business acquisitions and divestitures:
			Receivables, net		(27,764	)		5,956			208
��			Accrued revenue		(17,054	)		(10,514	)		(4,456	)
			Prepaid expenses		6,143			1,320			679
			Materials, supplies and gas in underground storage		(29,113	)		(5,337	)		(24,225	)
			Regulatory asset — gas charges recoverable from customers		(832	)		6,124			(4,061	)
			Accounts payable		35,303			10,480			(15,282	)
			Customer advances and amounts payable to customers		10,257			3,643			4,561
			Other		713			(1,016	)		(11,375	)
Net cash provided by (used for) operating activities					28,826			40,225			(12,545	)
Cash flows provided by (used for) investing activities
	Property additions — gas distribution				(38,739	)		(37,924	)		(28,323	)
	Property additions — corporate and other				(1,417	)		(988	)		(1,843	)
	Business acquisition, net of cash acquired				(3,076	)		—			—
	Proceeds from divestiture of discontinued construction services
	business, net of related expenses				—			21,290			—
	Proceeds from other property sales, net of retirement costs				(642	)		(1,164	)		1,683
	Proceeds from early retirement of a note receivable				—			7,838			—
	Proceeds from redemption of investment in unconsolidated subsidiary				1,240			—			—
	Changes in restricted cash				(2	)		(1,388	)		1,012
Net cash used for investing activities					(42,636	)		(12,336	)		(27,471	)
Cash flows provided by (used for) financing activities
	Issuance of common stock and common stock warrants, net of expenses				29,918			2,500			3,329
	Issuance of convertible cumulative preferred stock, net of expenses				66,302			—			—
	Issuance of convertible preference stock, net of expenses				—			45,590			—
	Repurchase of convertible preference stock and common stock warrants				(60,000	)		—			—
	Issuance (repayment) of notes payable and payment of related expenses				38,983			(43,074	)		(39,800	)
	Issuance of long-term debt, net of expenses				—			(167	)		247,931
	Repayment of long-term debt				(56,364	)		(29,965	)		(138,309	)
	Debt exchange and extinguishment costs				—			—			(24,030	)
	Payment of dividends on convertible cumulative preferred stock				(2,333	)		—			—
	Payment of dividends on common stock				—			(4,221	)		(8,235	)
	Change in book overdrafts included in current liabilities				(690	)		883			—
Net cash provided by (used for) financing activities					15,816			(28,454	)		40,886
Cash and cash equivalents
	Net increase (decrease)				2,006			(565	)		870
	Beginning of period				2,118			2,683			1,813
End of period				$	4,124		$	2,118		$	2,683

The accompanying notes to the consolidated financial statements are an integral part of these statements.

53

CONSOLIDATED STATEMENTS OF CAPITALIZATION

		December 31,
		2005			2004
		(In thousands, except for
		number of shares and par
		value)
Long-term debt
	6.50% senior notes due 2005	$	—		$	15,000
	3.77% senior notes due 2005		—			92
	6.40% senior notes due 2008		5,000			5,000
	7.125% senior notes due 2008		148,268			149,455
	6.49% senior notes due 2009		30,000			30,000
	7.03% senior notes due 2013		10,000			10,000
	7.75% senior notes due 2013		188,795			188,012
	8.00% senior notes due 2016		59,596			59,631
	10.25% subordinated notes due 2040		—			41,237
		$	441,659		$	498,427
	Less: Current maturities of long-term debt		—			15,092
		$	441,659		$	483,335
Convertible cumulative preferred stock $1 par value, 500,000 shares authorized; 350,000 and 0 shares outstanding		$	66,526		$	—
Series B convertible preference stock $1 par value, 70,000 shares authorized; 0 and 51,766 shares outstanding		$	—		$	48,405
Common shareholders’ equity
	Common stock, par value $1 per share — 100,000,000 shares authorized; 33,704,025 and 28,396,538 shares outstanding	$	33,704		$	28,397
	Capital surplus		241,944			217,073
	Unearned compensation associated with restricted stock		(795	)		—
	Accumulated comprehensive income (loss)		(9,073	)		(7,435	)
	Retained earnings (deficit)		(71,780	)		(71,949	)
		$	194,000		$	166,086
Total capitalization		$	702,185		$	697,826

The accompanying notes to the consolidated financial statements are an integral part of these statements.

54

CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDERS’ EQUITY

			Years Ended December 31,
			2005			2004			2003
			(In thousands)
Shares of common stock
	Beginning of year			28,397			28,059			18,682
		Issuance of common stock pursuant to a public offering		4,945			—			—
		Issuance of common stock pursuant to stock purchase contracts associated with the FELINE PRIDES securities		—			—			8,737
		Issuance of common stock pursuant to share-based compensation arrangements		14			9			12
		Issuance of restricted common stock		169			—			—
		Issuance of common stock for the DRIP and other		179			329			628
	End of year			33,704			28,397			28,059
Common stock
	Beginning of year		$	28,397		$	28,059		$	18,682
		Issuance of common stock pursuant to a public offering		4,945			—			—
		Issuance of common stock pursuant to stock purchase contracts associated with the FELINE PRIDES securities		—			—			8,737
		Issuance of common stock pursuant to share-based compensation arrangements		14			9			12
		Issuance of restricted common stock		169			—			—
		Issuance of common stock for the DRIP and other		179			329			628
	End of year		$	33,704		$	28,397		$	28,059
Capital surplus
	Beginning of year		$	217,073		$	214,779		$	120,089
		Issuance of common stock pursuant to a public offering, net of expenses		24,730			—			—
		Issuance of common stock pursuant to stock purchase contracts associated with the FELINE PRIDES securities, net of expenses		—			—			92,181
		Issuance of common stock pursuant to share-based compensation arrangements		70			47			44
		Issuance of restricted common stock		815			—			—
		Issuance of common stock for the DRIP and other		867			1,375			2,465
		Issuance of common stock warrants		—			741			—
		Repurchase of common stock warrants		(2,094	)		—			—
		Non-cash share-based compensation		483			131			—
	End of year		$	241,944		$	217,073		$	214,779
Unearned Compensation associated with restricted common stock
	Beginning of year		$	—		$	—		$	—
		Issuance of restricted common stock		(984	)		—			—
		Amortization of unearned compensation expense associated with restricted common stock		189			—			—
	End of year		$	(795	)	$	—		$	—
Accumulated comprehensive income (loss)
	Beginning of year		$	(7,435	)	$	(6,972	)	$	(7,597	)
		Minimum pension liability adjustment, net of income tax benefit (expense) of $1,008, $420 and $(200)		(1,872	)		(781	)		372
		Valuation adjustment for marketable securities, net of income tax expense of $31, $30 and $0		58			57			—
		Unrealized derivative gain (loss) on interest rate hedge from an investment in an affiliate		176			261			253
	End of year		$	(9,073	)	$	(7,435	)	$	(6,972	)
Retained earnings (deficit)
	Beginning of year		$	(71,949	)	$	(61,448	)	$	(21,152	)
		Net income (loss) available to common shareholders		169			(8,386	)		(29,955	)
		Cash dividends declared on common stock — $0.00, $0.08 and $0.35 per share		—			(2,115	)		(10,341	)
	End of year		$	(71,780	)	$	(71,949	)	$	(61,448	)

The accompanying notes to the consolidated financial statements are an integral part of these statements.

55

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

		Years Ended December 31,
		2005			2004			2003
		(In thousands)
Net income (loss)		$	12,275		$	(5,183	)	$	(29,955	)
	Minimum pension liability adjustment, net of income tax benefit (expense) of $1,008, $420 and $(200)		(1,872	)		(781	)		372
	Valuation adjustment for marketable securities, net of income tax expense of $31, $30 and $0		58			57			—
	Unrealized derivative gain (loss) on interest rate hedge from an investment in an affiliate		176			261			253
Total comprehensive income (loss)		$	10,637		$	(5,646	)	$	(29,330	)

The accompanying notes to the consolidated financial statements are an integral part of these statements.

56

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Note 1. Company Description and Significant Accounting Policies

     Company Description. SEMCO Energy, Inc., is a New York Stock Exchange-listed regulated public utility headquartered in Port Huron, Michigan. References to the “Company” mean SEMCO Energy, Inc., SEMCO Energy, Inc. and its subsidiaries, individual subsidiaries or divisions of SEMCO Energy, Inc. or the segments discussed below as appropriate in the context of the disclosure.

      The Company reports one reportable business segment: Gas Distribution. The Company’s Gas Distribution business segment distributes and transports natural gas to approximately 286,000 customers in Michigan and approximately 123,000 customers in Alaska. These operations are known together as the “Gas Distribution Business.” The Gas Distribution Business is subject to regulation, which is discussed in the “Rate Regulation” section below. This business segment accounted for approximately 99% of the Company’s 2005 consolidated operating revenues.

      The Company’s other business segments that do not meet the quantitative thresholds required to be reportable business segments (“non-separately reportable business segments”) are combined and included with the Company’s corporate division in a category the Company refers to as “Corporate and Other.” The Company’s non-separately reportable business segments primarily include operations and investments in information technology (“IT”) services, propane distribution, intrastate natural gas pipelines, and a natural gas storage facility. The IT services operation is headquartered in Michigan and provides IT services with a focus on mid-range computers, particularly the IBM I-Series (or AS-400) platform. The Company has reorganized its IT operations to focus them primarily on the Company’s IT needs, resulting in declining revenues from non-affiliated customers. The Company expects to continue to provide IT services to certain non-affiliated customers where it believes it can do so profitably. The Company’s propane distribution operation typically sells more than 4 million gallons of propane annually to retail customers in Michigan’s upper peninsula and northeast Wisconsin. The Company’s pipeline and storage operations operate natural gas transmission and storage facilities in Michigan.

     Discontinued Operations. During the first quarter of 2004, the Company began accounting for its construction services business as a discontinued operation and reclassified prior periods accordingly. In September 2004, the Company sold the assets of its construction services business to InfraSource Services, Inc. for approximately $21.3 million. For additional information, refer to Note 14.

     Basis of Presentation. The financial statements of the Company were prepared in conformity with accounting principles generally accepted in the United States. In connection with the preparation of the financial statements, management was required to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ materially from those estimates.

     Principles of Consolidation. The consolidated financial statements include the accounts of SEMCO Energy, Inc. and its wholly-owned subsidiaries. Investments in unconsolidated companies where the Company has significant influence, but does not control the entity, are reported using the equity method of accounting.

     Rate Regulation. The Gas Distribution Business is subject to regulation. The Michigan Public Service Commission (“MPSC”) has jurisdiction over the regulatory matters related to the Company’s Michigan customers, except for customers in the City of Battle Creek, Michigan, and nearby communities. The City Commission of Battle Creek (“CCBC”) has jurisdiction over the regulatory matters related to the Company’s customers in the City of Battle Creek, Michigan and nearby communities. The Regulatory Commission of Alaska (“RCA”) has jurisdiction over the regulatory matters related to the Company’s Alaska customers. These regulatory bodies have jurisdiction over, among other things, rates, accounting procedures, and standards of service. The approximate number of the Company’s customers located in service areas regulated by each of the three regulatory bodies is as follows: MPSC — 249,000; CCBC — 37,000; and RCA — 123,000.

57

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Note 1. Company Description and Significant Accounting Policies (continued)

      The Gas Distribution Business is subject to Statement of Financial Accounting Standards (“SFAS”) 71. Refer to Note 2 for additional information regarding SFAS 71.

     Cash and Cash Equivalents. Cash and cash equivalents include cash on hand, money market funds, and commercial paper with original maturities of three months or less.

     Restricted Cash. At December 31, 2005, and 2004, the Company had $1.6 million of restricted cash. Restricted cash includes the portion of a supplemental retirement trust account expected to be distributed within one year, and deposits to an escrow account to comply with credit requirements of two of the Company’s gas suppliers.

     Accounts Receivable. Trade accounts receivable are recorded at the billed amount and do not bear interest. The allowance for doubtful accounts is the Company’s best estimate of the amount of probable credit losses in existing accounts receivable. Allowance for doubtful accounts is based primarily on the aging of receivables, while also taking into consideration historical write-off experience and regional economic data. The Company reviews allowance for doubtful accounts monthly. Account balances are charged off against the allowance when the Company determines it is probable that certain individual receivables will not be recovered. Uncollectible accounts, or bad debt expense, was $2.4 million, $3.1 million and $3.6 million for the years 2005, 2004 and 2003, respectively.

     Accrued Revenue. Accrued revenue represents revenue earned in the current period but not billed to the customer until a future date, usually within one month.

     Gas in Underground Storage. The gas inventory of the Gas Distribution Business at December 31, 2005, and 2004 was reported at average cost. In general, commodity costs and variable transportation costs are capitalized as gas in underground storage. Fixed costs, primarily pipeline demand charges and storage charges, are expensed as incurred through the cost of gas.

     Property, Plant, Equipment and Depreciation. The Company’s property, plant and equipment are recorded at cost. The Company provides for depreciation on a straight-line basis over the estimated useful lives of the related property. The lives over which the Company’s significant classes of regulated and non-regulated depreciable property are depreciated are as follows (in years):

Regulated Property, Plant & Equipment		Non-Regulated Property, Plant & Equipment
(Gas Distribution Business)		(Corporate and Other)
Land	—	Intrastate gas pipelines	25
Underground gas storage property	25 — 39	Propane storage tanks	30
Gas transmission property	30 — 41	Computer & related equipment	5
Gas distribution property	19 — 58	Software	3
General property	5 — 34

      The ratio of depreciation to the average balance of regulated property was approximately 3.8%, 3.8% and 4.0% for the years 2005, 2004 and 2003, respectively. The ratio of depreciation to the average balance of non-regulated property approximated 3.5%, 4.2% and 4.9% for the years 2005, 2004 and 2003, respectively.

      Depreciation rates on the Company’s regulated property are set by the regulatory commissions that have jurisdiction over the property. The depreciation rates are intended to expense, over the expected life of the property, both the original cost of the property and the expected costs to remove or retire the property at the end of its useful life. The portion of depreciation expense related to expensing the original cost of the property is charged to accumulated depreciation while the portion related to expensing the expected costs to remove or retire the regulated property, less expected salvage proceeds, is charged to a regulatory liability. This regulatory liability is known in the utility industry as negative salvage value. When the regulated property is ultimately retired, or otherwise disposed of in the ordinary course of business, the original cost of the property

58

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Note 1. Company Description and Significant Accounting Policies (continued)

is charged to accumulated depreciation, and the actual removal costs, less salvage proceeds are charged to the regulatory liability. With respect to the retirement or disposal of non-regulated assets, the resulting gains or losses are recognized in income.

      During 2004, under the provisions of SFAS 144, “Accounting for Impairment or Disposal of Long-Lived Assets,” the Company recorded a $0.2 million charge in the fourth quarter of 2004 for the impairment of long-lived assets. The impairment charge was a result of the Company’s decision to exit the residential portion of its Internet Service Provider (“ISP”) operation that was part of its IT business. The $0.2 million before-tax charge for impairment of long-lived assets is reflected in the Company’s Consolidated Statements of Operations in operations and maintenance expenses.

      During 2003, under the provisions of SFAS 144, the Company recorded a $2.8 million charge in the third quarter of 2003 for the impairment of long-lived assets. The $2.8 million before-tax charge is included in the Company’s Consolidated Statements of Operations, as part of the loss from the discontinued construction services business.

     Goodwill and Goodwill Impairment. Goodwill represents the excess of purchase price and related costs over the value assigned to the net identifiable assets of businesses acquired. The Company accounts for goodwill under the provisions of SFAS 141, “Business Combinations”, and SFAS 142, “Goodwill and Other Intangible Assets.” SFAS 141 addresses financial accounting and reporting for all business combinations and requires that all business combinations entered into subsequent to June 2001 be recorded under the purchase method. This statement also addresses financial accounting and reporting for goodwill and other intangible assets acquired in a business combination at acquisition. SFAS 142 addresses financial accounting and reporting for intangible assets acquired individually or with a group of other assets at acquisition. This statement also addresses financial accounting and reporting for goodwill and other intangible assets subsequent to their acquisition.

      On June 1, 2005, the Company acquired substantially all of the assets and certain liabilities of Peninsular Gas Company (“Peninsular Gas”). Approximately $0.1 million of the purchase price was allocated to goodwill. Refer to Note 14 for further information regarding this transaction.

      The Company is required to perform impairment tests on its goodwill annually or at any time when events occur which could impact the value of the Company’s business segments. If an impairment test of goodwill shows that the carrying amount of the goodwill is in excess of the fair value, a corresponding impairment loss would be recorded in the Consolidated Statements of Operations.

      The 2005 annual impairment tests were performed for the Company’s business segments and indicated that there was no impairment of goodwill.

      During 2004, it was determined that all of the goodwill associated with the Company’s IT services business was impaired. The impairment charge was a result of the Company’s decision to exit the residential portion of its ISP operation. All of the goodwill for the Company’s IT services business was related to the residential ISP operation. The $0.2 million before-tax charge for impairment of goodwill is reflected in the Company’s Consolidated Statements of Operations in operating expenses. The 2004 annual goodwill impairment test was also performed for each of the Company’s other business segments during the third and fourth quarters of 2004 and indicated that there was no impairment of goodwill.

59

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Note 1. Company Description and Significant Accounting Policies (continued)

      During 2003, it was determined that all of the goodwill associated with the Company’s construction services business ($17.6 million) was impaired. The $17.6 million before-tax charge for impairment of goodwill is reflected in the Company’s Consolidated Statements of Operations, as part of the loss from the discontinued construction services operations. The 2003 annual goodwill impairment test was also performed for each of the Company’s other business units during the third and fourth quarters of 2003 and indicated that there was no impairment of goodwill. The following table summarizes changes in the carrying amount of goodwill for the past two years:

	Gas
	Distribution		Corporate			Total
	Segment		and Other			Company
	(In thousands)
Balance as of December 31, 2003	$	140,227	$	3,208		$	143,435
Impairment charge		—		(152	)		(152	)
Balance as of December 31, 2004	$	140,227	$	3,056		$	143,283
Goodwill acquired in a business acquisition on June 1, 2005		91		—			91
Impairment charge		—		—			—
Balance as of December 31, 2005	$	140,318	$	3,056		$	143,374

     Unamortized Debt Expense. The Company defers expenses incurred in connection with the issuance of debt and amortizes these deferred expenses over the terms of the debt. If the underlying debt is retired or refinanced, any unamortized expenses are charged to expense in the Company’s Consolidated Statements of Operations, except in situations where the debt was specifically allocated to the Company’s Gas Distribution Business. In instances when debt allocated specifically to the Gas Distribution Business is refinanced, any unamortized expenses are deferred as a regulatory asset and amortized over the term of the new debt.

     Customer Advance Payments. The Company receives advance payments from customers who sign up for the Company’s budget payment program. This program is designed so customers can pay their estimated annual gas charges in equal monthly payments. As a result, customers make advance payments during the non-heating season when consumption is generally low, and then utilize these advance payments to pay for a portion of their gas bills during the heating season, when consumption is generally high. Customer advance payments also include deposits the Company receives from customers to cover customer credit risk.

     Revenue Recognition. The Gas Distribution Business bills monthly on a cycle basis and follows the utility industry practice of recognizing accrued revenue for services rendered to its customers but not billed at month end. Gas sales revenue is comprised of three components: (i) monthly customer service fees; (ii) volumetric distribution charges; and (iii) volumetric gas commodity charges. Monthly customer service fees represent fixed fees charged to customers. Distribution charges are charged to customers based on the volume of gas consumed by customers. Gas commodity charges represent the cost of gas consumed by customers. As discussed in more detail in the Cost of Gas section below, the Company generally does not earn any income on the gas commodity charge portion of customer rates.

      The Company’s other businesses recognize revenues in the period that services are rendered or products are delivered to customers.

     Cost of Gas, Gas Charges Recoverable from Customers, and Amounts Payable to Customers. The Company’s gas distribution area regulated by the MPSC operated with an MPSC-approved gas cost recovery (“GCR”) pricing mechanism during 2003, 2004 and 2005. The Alaska-based gas distribution operation (“ENSTAR”) has an RCA-approved gas cost adjustment (“GCA”) pricing mechanism, which is similar to the GCR pricing mechanism. Both of these pricing mechanisms (hereinafter referred to as “GCR” pricing mechanisms) are designed so that, in the absence of any cost disallowances, the Company’s cost of gas

60

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Note 1. Company Description and Significant Accounting Policies (continued)

purchased is passed-through to the Company’s customers and, therefore, the Company does not recognize any income on the gas commodity charge portion of customer rates.

      The GCR pricing mechanisms allow for the adjustment of rates charged to customers for increases and decreases in the cost of gas purchased by the Company for sale to customers. However, in the Company’s gas distribution area regulated by the MPSC, the GCR pricing mechanism is subject to a MPSC review of the Company’s GCR gas purchase plans and actual gas purchases. A GCR gas purchase plan is filed annually with the MPSC by December 31 of each year for the upcoming April 1 to March 31 GCR period. A reconciliation case is filed by June 30 of each year to reconcile actual gas purchases during the previous April 1 to March 31 GCR period to the GCR gas purchase plan for the period. Both the GCR gas purchase plan and the reconciliation case may involve MPSC reviews of Company actions and decisions and potential cost disallowances. When costs are disallowed, such costs are expensed in the cost of gas but are not recovered in rates.

      The annual GCR period in Alaska runs from January 1 to December 31. The GCR rate established by the RCA reflects the pricing mechanisms in certain long-term gas supply contracts approved by the RCA and recovers the cost of natural gas purchased by the Company under those contracts.

      Under the GCR pricing mechanisms, the gas commodity charge portion of customers’ gas rates (which is also referred to as the “GCR rate”) in Alaska and the Company’s Michigan service area regulated by the MPSC is generally adjusted annually to reflect the estimated cost of gas purchased for the upcoming12-month GCR period. Any difference between actual allowed cost of gas purchased and the estimate for a particular GCR period is deferred as either a gas charge over- or under-recovery and included in customer GCR rates during the next GCR period. A gas charge over-recovery occurs when the estimated cost of gas exceeds the actual cost of gas purchased and is reflected in Amounts Payable to Customers in the current liabilities section of the Company’s Consolidated Statements of Financial Position. A gas charge under-recovery occurs when the actual cost of gas purchased exceeds the estimated cost of gas and is reflected in Gas Charges Recoverable from Customers in the current assets section of the Company’s Consolidated Statements of Financial Position. The GCR rate may be adjusted more frequently than annually if it is determined that there are significant variances from the estimates used in the annual determination. At December 31, 2005, the Company had $12.3 million recorded in current liabilities for Amounts Payable to Customers and $1.0 million recorded in current assets for Gas Charges Recoverable from Customers, under the GCR pricing mechanisms.

      The Company’s gas service area regulated by the CCBC had been operating under a fixed gas charge program during 2003, 2004 and the first three months of 2005. Under that program the Company suspended its GCR pricing mechanism and utilized a fixed gas charge in the rates for customers located in its service area regulated by the CCBC (“CCBC-regulated customers”). The Company was able to offer this GCR suspension and fixed rate mainly as a result of a gas supply agreement covering CCBC-regulated customers. Under the terms of the agreement, the gas supplier provided a significant portion of the Company’s natural gas requirements, and managed the Company’s natural gas supply and the supply aspects of transportation and storage operations for the Company’s gas distribution area regulated by the CCBC, at a cost that was, in most instances, below the fixed price charged to CCBC-regulated customers. As a result, during 2003, 2004 and the first quarter of 2005, the Company retained any gas costs savings that resulted when the cost of purchased natural gas was below the fixed price charged to CCBC-regulated customers.

      However, beginning April 1, 2005, the Company once again began to use a GCR pricing mechanism in the service area regulated by the CCBC and therefore, no longer retains any gas cost savings. The GCR pricing mechanism calls for the GCR rate to be revised monthly, to track and recover changes in the cost of natural gas purchased by the Company for use by CCBC-regulated customers.

61

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Note 1. Company Description and Significant Accounting Policies (continued)

     Self-Insurance. The Company is self-insured for health care costs up to $75,000 per subscriber annually. Insurance coverage is carried for risks in excess of this amount. The Company recognized self-insured health care expense of approximately $2.4 million, $4.0 million, and $4.1 million for the years ended December 31, 2005, 2004 and 2003, respectively. Estimated claims incurred but not reported were $0.6 million and $0.8 million as of December 31, 2005, and 2004, respectively, and are included in other accrued liabilities in the Consolidated Statement of Financial Position.

     Income Taxes. The Company files a consolidated federal income tax return and income taxes are allocated among the Company’s subsidiaries and divisions based on their separate taxable income. Investment tax credits (“ITC”) utilized in prior years for income tax purposes are deferred for financial accounting purposes and are amortized through credits to the income tax provision over the lives of the related property. For additional information, refer to Note 3.

     Share-Based Compensation. The Company accounts for share-based compensation arrangements in accordance with SFAS 123, “Accounting for Stock-Based Compensation,” as amended by SFAS 148, “Accounting for Stock-Based Compensation — Transition and Disclosure.” In accordance with SFAS 123, the Company has chosen to account for certain of its share-based compensation arrangements under Accounting Principles Board (“APB”) Opinion No. 25, “Accounting for Stock Issued to Employees” (“APB 25”) for purposes of determining net income but must present the pro forma disclosures required by SFAS 123. As a result, the Company’s net income (loss) as reported in its Consolidated Statements of Operations reflects compensation expense for certain of its share-based compensation arrangements calculated using the intrinsic value method provided for under the provisions and related interpretations of APB 25 rather than the fair value method provided for under SFAS 123. If all of the Company’s share-based compensation expense had been determined in a manner consistent with the provisions of SFAS 123, the Company’s net income (loss) available to common shareholders and related earnings (loss) per share would have been reduced to the pro forma amounts set forth in the table below. Refer to Note 9 for further information about the Company’s share-based compensation arrangements. For information on a new accounting standard for share-based compensation which was adopted by the Company on January 1, 2006, refer to the “New Accounting Standards” section within this note.

			Years Ended December 31,
			2005			2004			2003
			(In thousands, except per share
			amounts)
Net income (loss) available to common shareholders
	As reported		$	169		$	(8,386	)	$	(29,955	)
		Add back total share-based compensation expense included in reported net income, net of related tax effects		492			122			36
		Deduct total share-based compensation expense determined under fair value based method for all awards, net of related tax effects		755			330			380
	Pro forma		$	(94	)	$	(8,594	)	$	(30,299	)
Earnings (loss) per share — basic
	As reported		$	0.01		$	(0.30	)	$	(1.34	)
	Pro forma		$	—		$	(0.30	)	$	(1.36	)
Earnings (loss) per share — diluted
	As reported		$	0.01		$	(0.30	)	$	(1.34	)
	Pro forma		$	—		$	(0.30	)	$	(1.36	)

62

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Note 1. Company Description and Significant Accounting Policies (continued)

     New Accounting Standards. In December 2004, the Financial Accounting Standards Board (“FASB”) issued SFAS 123-R (Revised 2004) — “Share-Based Payment.” This standard supercedes APB No. 25 and requires recognition of expense in the financial statements of the cost of share-based payment transactions, including stock option awards, based on the fair value of the award at the grant date. This statement also amends SFAS 95, “Statement of Cash Flows,” to require that excess tax benefits related to the excess of the share-based compensation deductible for tax purposes over the compensation recognized for financial reporting purposes be classified as cash inflows from financing activities rather than as a reduction of taxes paid in operating activities. The provisions of this standard are effective for public companies for annual periods beginning after June 15, 2005, and thus are not reflected in the accompanying consolidated financial statements. The Company adopted this statement on January 1, 2006, using the modified prospective method described in SFAS 123-R. The Company believes that the pro forma amounts set forth above provide a reasonable estimate of the impact of this standard on the Company’s Consolidated Financial Statements.

      In March 2005, the FASB issued Interpretation No. 47, Accounting for Conditional Asset Retirement Obligations. This Interpretation clarifies the term “conditional asset retirement obligation” as used in SFAS No. 143. The term refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity. The obligation to perform the asset retirement activity is unconditional even though uncertainty exists about the timing and/or method of settlement. Accordingly, an entity is required to recognize a liability for the fair value of a conditional asset retirement obligation if the fair value of the liability can be reasonably estimated. The fair value of a liability for the conditional asset retirement obligation should be recognized when incurred. This Interpretation also clarifies when an entity would have sufficient information to reasonably estimate the fair value of an asset retirement obligation. As a result of the adoption of this Interpretation by the Company in the fourth quarter of 2005, certain asset retirement obligations were identified, and they are estimated to cost the Company approximately $24.1 million at the date of removal. The present value of this obligation at December 31, 2005, was $2.3 million, which was recorded in the fourth quarter of 2005.

      In May 2005, the FASB issued SFAS No. 154, “Accounting Changes and Error Corrections” (“SFAS No. 154”). This statement establishes new standards on accounting for changes in accounting principles. Pursuant to SFAS No. 154, all such changes must be accounted for by retrospective application to the financial statements of prior periods unless it is impracticable to do so. SFAS No. 154 completely replaces APB Opinion No. 20 and SFAS No. 3, though it carries forward the guidance in those pronouncements with respect to accounting for changes in estimates, changes in the reporting entity and the correction of errors. This statement is effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005. The Company does not believe the adoption of this standard will have a material impact on its financial position and results of operations.

     Statements of Cash Flows. For purposes of the Consolidated Statements of Cash Flows, the Company considers all highly liquid investments purchased with original maturities of three months or less to be cash and cash equivalents.

      Dividends associated with the Company’s Convertible Preference Stock (“CPS”) were $0.9 million and $3.2 million in 2005 and 2004, respectively. These dividends were paid in additional shares of CPS, or what is commonly referred to as stock dividends orpayment-in-kind dividends. The issuance of stock dividends is a non-cash financing activity and therefore is not reflected in the Consolidated Statements of Cash Flows. Refer to Note 4 for further information regarding the issuance of stock dividends on the CPS and the subsequent repurchase of the CPS in March 2005.

      In August 2003, the Company issued approximately 8.74 million shares of Common Stock for $101 million through the mandatory purchase obligation under the terms of stock purchase contracts, which were a component of the Company’s FELINE PRIDES securities. The Company also retired approximately

63

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Note 1. Company Description and Significant Accounting Policies (continued)

$101 million of 9% trust preferred securities, which were also a component of the FELINE PRIDES securities. These transactions were non-cash financing activities and therefore both the issuance of the $101 million of Common Stock and the retirement of the $101 million of 9% trust preferred securities are not reflected in the Consolidated Statements of Cash Flows. Refer to Note 4 for further information.

      In May 2003, the Company completed an offering of an aggregate of $300 million of senior unsecured notes. The Company used approximately $92.3 million of the new notes in an exchange for other outstanding debt of the Company. The debt exchange was a non-cash financing activity and therefore is not reflected in the Consolidated Statements of Cash Flows. Refer to Note 4 for further information regarding the debt exchange.

      Supplemental cash flow information for the years ended December 31, 2005, 2004, and 2003, is summarized in the following table.

		Years Ended December 31,
		2005			2004		2003
		(In thousands)
Cash paid during the year for:
	Interest and dividends on trust preferred securities	$	39,443		$	41,216	$	49,173
	Income taxes, net of (refunds)	$	(1,840	)	$	3,500	$	(3,000	)

Note 2. Regulatory Matters

     MPSC. In December 2004, the Company filed a base rate increase request totaling $11.65 million with the MPSC. Among other things, the Company proposed an increase in customer service fees and a weather normalization rider, for the purpose of mitigating the impact of weather on customer bills and the Company’s financial results. On March 29, 2005, the MPSC approved a settlement with the Company, which, at the time of settlement, was expected to produce an additional $7.1 million in annual revenue from customers in the Company’s MPSC-regulated service area. Increases in the fixed customer charge for several commercial and industrial customer classes and the increase in fees for certain services mitigate some of the effect of weather on the Company’s revenues. The settlement did not include the Company’s proposed increase in residential customer service fees or weather normalization rider. The rate adjustments authorized by this settlement became effective on March 30, 2005.

      The Company filed its application for MPSC approval of its GCR plan and rate on December 29, 2004, and the MPSC approved a settlement of that case on September 20, 2005. The approved base GCR rate was $7.9055 per Mcf, plus a NYMEX-based contingency adjustment that brought the rate to $9.6165 per Mcf. The $9.6165 rate was effective with the October 2005 billing month.

      As a result of substantial increases in gas prices in the United States, on October 4, 2005, the Company filed a petition with the MPSC, to reopen the settlement and re-set its GCR rate for the12-month period ending March 31, 2006. On October 6, 2005, the MPSC issued an order reopening the Company’s GCR proceeding and setting an expedited timetable for the proceeding. On October 28, 2005, the MPSC approved a settlement under which the Company increased its GCR rate to $11.2684 per Mcf from $9.6165 per Mcf, effective for usage in the November 2005 billing month and through the end of the March 2006 billing month. The settlement provided that the Company may not seek further GCR rate increases for the remainder of this GCR year which ends in March 2006.

      On October 26, 2005, the MPSC approved another settlement under which the former customers of Peninsular Gas will pay an increased GCR rate ($12.09 per Mcf) beginning in the November 2005 billing month through the March 2006 billing month. The Company now serves these customers after having purchased the assets of Peninsular Gas in June 2005. This increase affects approximately 4,000 customers.

64

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Note 2. Regulatory Matters (continued)

      The Company seeks to end its GCR period ending on March 31 of each year, with no significant under-recovery or over-recovery. In February 2006, because natural gas prices had fallen from earlier levels and to attempt to end the GCR period with no significant under- or over-recovery of gas costs, the Company reduced its GCR factor to $9.7600/ Mcf for customers in its MPSC regulated service area, including the former customers of Peninsular Gas.

      In an attempt to provide supplemental assistance to customers who are unable to pay their bills on time or in full and to price lost and unaccounted for (“LAUF”) natural gas volumes at current market prices in customer rates, the Company has proposed to the MPSC (i) the establishment of an assistance program to help eligible low income customers pay their gas bills, and (ii) a change in how the Company accounts for its expenses for LAUF gas and uncollectible customer accounts (“uncollectibles”). The proposed assistance program would allow the Company to charge-off one half of the commodity charge portion of an eligible customer’s account up to $550 in certain circumstances. The Company also proposed, to ensure more timely cost recovery, that the commodity portion of LAUF gas and uncollectibles be collected via the GCR rate. To offset these recoveries through the GCR rate, the Company also proposed to reduce its volumetric distribution charges by removing the amount of the rate case allowance for LAUF gas and the gas commodity portion of all uncollectibles from base rates. The Company would instead record LAUF gas costs and the gas commodity portion of uncollectibles, including the charge-offs under the assistance program, to cost of gas sold. Additionally, as a contribution, the Company proposed to credit up to $150,000 annually to offset the charge-offs made to uncollectibles pursuant to the proposed assistance program. On February 13, 2006, the Company filed to withdraw these proposals, with the intention of resubmitting some or all of the proposals, in the same form or with modifications, in one or more future proceedings.

      On October 14, 2004, the MPSC initiated a generic proceeding involving all Michigan electric and gas utilities to review SFAS 143 “Accounting for Asset Retirement Obligations,” Federal Energy Regulatory Commission Order No. 631, “Accounting, Financial Reporting, and Rate Filing Requirements for Asset Retirement Obligations,” and related accounting and ratemaking issues. As directed by the MPSC, on March 15, 2005, the Company filed responses, in the form of testimony, to various questions raised by the MPSC regarding the Company’s accounting practices for property retirements, including the cost of removal. Among other things, this proceeding involves an examination of possible changes in accounting for property retirements, for rate-making purposes. On December 5, 2005, the Administrative Law Judge issued a Proposal for Decision recommending that the proceedings be dismissed on procedural grounds. The matter awaits a decision by the MPSC.

     CCBC. In November 2004, the Company filed a base increase request totaling $5.07 million with the CCBC. In February 2005, the CCBC approved a settlement , which, at the time of settlement, was expected to produce an additional $3.55 million in annual revenue, to be effective with the first customer billing cycle of April 2005, with additional annual revenue increases of $150,000 to be put into effect beginning in April of 2006, and 2007, respectively, subject to certain conditions, including the Company’s making annual contributions to assist low income customers in paying their bills for service. With certain exceptions, the Company has agreed not to request a further base rate increase to be effective before April 1, 2008. These revenue increases are to be recovered, in part, through increased customer service fees.

      The GCR rate for the approximately 37,000 customers in the service territory regulated by the CCBC is revised monthly, to track and recover changes in the cost of natural gas purchased by the Company for use by CCBC-regulated customers. The Company seeks to end its GCR period (which ends on March 31 of each year) with no significant gas charge under-recovery or over-recovery.

      The Company and the CCBC announced on October 5, 2005, that they will ask the MPSC to assume jurisdiction over this service area. In 2006, the Company and the CCBC plan to file a joint application with the MPSC asking for approval of this jurisdictional change. The Company had previously agreed to support such a request as part of a base rate increase settlement with the CCBC. The Company does not believe that

65

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Note 2. Regulatory Matters (continued)

this proposed change will have a material impact on its natural gas rates, results of operations or financial position.

     RCA. On June 20, 2005, the RCA issued an order requiring ENSTAR to file a revenue requirement and cost of service study (including rate design data) with the RCA by June 6, 2008 (using a test year ended December 31, 2007). In addition, ENSTAR is required to file a depreciation study of utility plant (as of December 31, 2006) by June 1, 2007. These filings also will include the Company’s Alaska Pipeline Company (“APC”) subsidiary.

     Regulatory Assets and Liabilities. The Gas Distribution Business is subject to the provisions of SFAS 71. The provisions of SFAS 71 allow the Company to defer expenses and income as regulatory assets and liabilities in the Consolidated Statements of Financial Position when it is probable that those expenses and income will be allowed in the rate setting process in a period different from the period in which they would have been reflected in the Consolidated Statements of Operations by an unregulated entity. These deferred regulatory assets and liabilities are then included in the Consolidated Statements of Operations in the periods in which the same amounts are reflected in rates. Management’s assessment of the probability of recovery or pass-through of regulatory assets and liabilities requires judgment and interpretation of laws and regulatory commission orders. If, for any reason, the Company ceases to meet the criteria for application of regulatory accounting treatment for all or part of its operations, the regulatory assets and liabilities related to those portions ceasing to meet such criteria would be eliminated from the Consolidated Statements of Financial Position and included in the Consolidated Statements of Operations for the period in which the discontinuance of regulatory accounting treatment occurs. Such amounts would be classified as extraordinary items. Criteria that give rise to the discontinuance of SFAS 71 include (i) increasing competition that restricts the ability of the Gas Distribution Business to charge prices to recover specific costs, and (ii) a significant change in the manner in which rates are set by regulatory agencies from cost-based regulation to another form of regulation. The Company’s review of these criteria currently supports the continuing application of SFAS 71.

66

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Note 2. Regulatory Matters (continued)

      The following table summarizes the regulatory assets and liabilities recorded in the Consolidated Statements of Financial Position, as well as the remaining period, as of December 31, 2005, over which the Company expects to realize or settle the assets or liabilities.

			December 31,
			2005		2004		Remaining Period
			(In thousands, except number of years)
Regulatory assets
	Current
		Gas charges recoverable from customers	$	971	$	137		1 year
	Noncurrent
		Deferred retiree medical costs	$	6,294	$	7,193		7 years
		Deferred loss on retirement of debt		1,827		2,133		5 — 11 years
		Deferred asset retirement obligation		1,820		—		15 — 35 years
		Other		2,661		2,736		1 — 10 years
			$	12,602	$	12,062
Regulatory liabilities
	Current
		Amounts payable to customers (gas cost overrecovery)	$	12,281	$	5,624		1 year
	Noncurrent
		Negative salvage value	$	56,627	$	54,094		15 — 40 years
		Tax benefits amortizable to customers		2,235		2,731		8 years
		Unamortized investment tax credits		352		617		1 year
			$	59,214	$	57,442

67

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Note 3. Income Taxes

     SFAS 109. The Company accounts for income taxes in accordance with SFAS 109, “Accounting For Income Taxes.” SFAS 109 requires an annual measurement of deferred tax assets and deferred tax liabilities based upon the estimated future tax effects of temporary differences and carry-forwards.

		Years Ended December 31,
		2005			2004			2003
		(In thousands)
Federal income tax expense (benefit):
	Current	$	—		$	(83	)	$	460
	Deferred to future periods		5,751			(1,546	)		(11,172	)
	Amortization of deferred investment tax credits (“ITC”)		(265	)		(265	)		(296	)
State income tax expense (benefit):
	Current		248			34			926
	Deferred to future periods		599			(2,111	)		324
Total income tax expense (benefit)		$	6,333		$	(3,971	)	$	(9,758	)
Less amounts included in:
	Minority interest — dividends on trust preferred securities		—			—			(2,316	)
	Discontinued operations		312			(3,504	)		(7,362	)
Income tax expense (benefit), excluding amounts shown separately		$	6,021		$	(467	)	$	(80	)

     Reconciliation of Statutory Rate to Effective Rate. The table below provides a reconciliation of the difference between the Company’s provision for income taxes and income taxes computed at the statutory rate.

		Years Ended December 31,
		2005			2004			2003
		(In thousands)
Net Income (loss)		$	12,275		$	(5,183	)	$	(29,955	)
	Add back income tax expense (benefit)		6,333			(3,971	)		(9,758	)
Pre-tax income (loss)		$	18,608		$	(9,154	)	$	(39,713	)
Computed federal income tax expense (benefit)		$	6,513		$	(3,204	)	$	(13,899	)
Amortization of deferred ITC			(265	)		(265	)		(296	)
State income tax expense, net of federal taxes			550			880			812
Change in estimate of prior years’ state income taxes, net of federal taxes			—			(2,230	)		—
Goodwill impairment charge not deductible for tax purposes			—			—			4,095
Other			(465	)		848			(470	)
Total income tax expense (benefit)		$	6,333		$	(3,971	)	$	(9,758	)

     Deferred Income Taxes. Deferred income taxes arise from temporary differences between the tax basis of assets and liabilities and their reported amounts in the Company’s financial statements. At December 31, 2005, and 2004, there was a valuation allowance of $0.4 million and $0.6 million, respectively, recorded against deferred tax assets. The Company also has an estimated net operating loss (“NOL”) carryforward for federal tax purposes of $96 million at December 31, 2005, of which an estimated $4 million expires in 2021, $22 million expires in 2022, $53 million expires in 2023 and $17 million expires in 2024. The Company’s

68

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Note 3. Income Taxes (continued)

ability to utilize its NOLs is limited by the Internal Revenue Code. However, the Company currently expects that it will achieve enough taxable income in future years to utilize its NOLs prior to their expiration.

      The table below shows the principal components of the Company’s deferred tax assets (liabilities).

	December 31,
	2005			2004
	(In thousands)
Property, plant and equipment	$	(57,702	)	$	(56,207	)
Retiree medical benefit liability		(200	)		303
Retiree medical benefit regulatory assets		(2,203	)		(2,518	)
Deferred ITC		151			339
Unamortized debt expense		(499	)		(613	)
Property taxes		(1,757	)		(2,629	)
Goodwill		(11,178	)		(8,722	)
Other comprehensive income — minimum pension liability		4,932			3,924
Other comprehensive income — valuation adjustment		(61	)		(30	)
Gas in underground storage		1,312			(514	)
Gas charge over-recovery		3,870			1,879
Net operating loss carryforward		33,503			38,851
AMT credit carryforward		2,276			2,276
Valuation allowance for deferred tax assets		(361	)		(580	)
Other		2,547			3,824
Total deferred taxes	$	(25,370	)	$	(20,417	)
Gross deferred tax liabilities	$	(108,837	)	$	(99,670	)
Gross deferred tax assets		83,828			79,833
Valuation allowance for deferred tax assets		(361	)		(580	)
Total deferred taxes	$	(25,370	)	$	(20,417	)

Note 4. Capitalization

     Common Shareholders’ Equity. On August 15, 2005, the Company completed an offering of 4,945,000 shares of Common Stock, at a public offering price of $6.32 per share. The aggregate gross proceeds of the offering were $31.3 million, with net proceeds of approximately $30.0 million after deducting underwriting discounts and commissions. The proceeds from the completion of this offering were used to redeem all of the Company’s outstanding 10.25% Series A Subordinated Debentures due 2040 (“10.25% Subordinated Notes”) held by the Company’s unconsolidated capital trust subsidiary, SEMCO Capital Trust I (the “Trust”), as discussed below.

      During 2005, the Company issued 176,583 shares of restricted Common Stock to members of the Company’s Board of Directors (“Board”) as part of the compensation for their services. The restrictions on 7,833 of those shares were waived due to the immediate retirement eligibility of the two individuals who were granted those shares. The restricted shares of Common Stock vest over periods of up to three years and the value of the restricted Common Stock at the time of issuance ($1.0 million) was added to the Company’s common shareholders equity. There is an offsetting account, which is also recorded in common shareholders’ equity, that represents the unearned compensation associated with the restricted Common Stock and, as of December 31, 2005, amounted to $0.8 million.

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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Note 4. Capitalization (continued)

      During 2005, 2004, and 2003, the Company issued approximately 40,000, 192,000 and 478,000 shares, respectively of its Common Stock to the Company’s Direct Stock Purchase and Dividend Reinvestment Plan (“DRIP”) to meet the dividend reinvestment and stock purchase requirements of its participants.

      The Company issued approximately 144,000, 145,000 and 162,000 shares of Company Common Stock to certain of the Company’s employee benefit and director deferred compensation plans in 2005, 2004, and 2003, respectively. Of these issuances, approximately 6,000, 9,000, and 12,000 are related to director deferred compensation. Refer to Note 9 for further information on directors’ stock-based compensation.

      On June 24, 2004, the Company suspended the quarterly cash dividend on the Company’s Common Stock, with the objective of supplementing free cash flow. This decision also reflects the Company’s desire to retain cash in order to strengthen the Company’s balance sheet, enhance financial flexibility and to be better positioned to grow the Company’s Gas Distribution Business in the future.

      As discussed below under “Convertible Preference Stock and Stock Warrants,” in March 2004, warrants to purchase 905,565 shares of Common Stock (“Warrants”) were issued in conjunction with the issuance of CPS. The net proceeds associated with the Warrants, approximately $0.7 million, were included in capital surplus in the common shareholders’ equity section of the Consolidated Statements of Financial Position at December 31, 2004. In March 2005, the Company paid $2.1 million to repurchase these Warrants. The $2.1 million paid to repurchase the Warrants is reflected in common shareholders’ equity as a decrease in capital surplus at December 31, 2005.

      In August 2003, the Company issued approximately 8.74 million shares of Common Stock for $101 million through the mandatory stock purchase obligation specified under the terms of the stock purchase contracts, which were a component of the FELINE PRIDES securities. As discussed below under “Other Matters Regarding Trust Preferred Securities,” the Company also retired approximately $101 million of 9% trust preferred securities in conjunction with this issuance of Common Stock. The issuance of the 8.74 million shares of Common Stock and the retirement of the 9% trust preferred securities were non-cash financing activities and, therefore, neither are reflected in the Company’s Consolidated Statements of Cash Flows.

     Convertible Preference Stock and Stock Warrants. During 2004, the Company issued through a private placement, $50 million of CPS and Warrants to K-1 GHM, LLLP, an affiliate of a private equity firm, k1 Ventures Limited (“K-1”). The private placement included 50,000 shares of CPS and Warrants to purchase 905,565 shares of the Company’s Common Stock. The net proceeds from this issuance were approximately $46.3 million. The portion of the net proceeds associated with the Warrants, approximately $0.7 million, was included in the common shareholders’ equity section of the Consolidated Statements of Financial Position as an increase in capital surplus.

      In connection with K-1’s purchase of the CPS and Warrants, action by the RCA was needed on the issue of whether a change of control occurred as a result of that investment in the Company. When it became apparent that it would be difficult to obtain the desired rulings, the Company and K-1 began negotiations for the repurchase of the CPS and Warrants. For further information concerning the regulatory approvals sought in connection with K-1’s investment in the Company, refer to the “Other Contingencies” section of Note 13.

      On March 8, 2005, the Company reached an agreement with K-1 to repurchase all of the outstanding CPS shares (52,543) and Warrants held by K-1. On March 15, 2005, the Company completed this repurchase. The aggregate repurchase price under the agreement was $60 million. Approximately $57.9 million of the repurchase price related to the CPS and the remainder, approximately $2.1 million, related to the Warrants. The repurchase price for the CPS included a premium over the book value of the CPS of approximately $8.2 million. The $8.2 million repurchase premium payment is reflected in the Company’s Consolidated Statements of Operations for the year ended December 31, 2005. The $2.1 million paid to repurchase the Warrants is included in capital surplus in the common shareholder’s equity section of the

70

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Note 4. Capitalization (continued)

Consolidated Statements of Financial Position. During 2005 and 2004, the Company paid stock dividends on the CPS of 777 and 1,766 additional shares of CPS, respectively.

     5% Series B Convertible Cumulative Preferred Stock. On March 15, 2005, concurrent with and in order to fund the repurchase of CPS and Warrants from K-1, the Company completed the offering of 5% Series B Convertible Cumulative Preferred Stock (“Preferred Stock”) to qualified institutional buyers pursuant to Rule 144A under the Securities Act of 1933 (the “Act”) and to persons in offshore transactions in reliance on Regulation S under the Act. In connection with the offering, the Company sold 325,000 shares of Preferred Stock. The gross proceeds from this offering were approximately $65.0 million.

      The Company also granted the initial purchasers a30-day option to purchase up to an additional 25,000 shares of Preferred Stock in connection with the offering. On March 22, 2005, the sale of an additional 25,000 shares of Preferred Stock was completed pursuant to the exercise of the option by the initial purchasers. The gross proceeds from the sale of the additional shares were approximately $5.0 million.

      Of the proceeds from this combined offering, $60 million was used to fund the repurchase of CPS and Warrants from K-1. The remaining proceeds were used to redeem $10.3 million of the Company’s 10.25% Subordinated Notes, held by the Trust, on April 29, 2005. The Trust, in turn, used the proceeds to redeem 400,000 shares of its 10.25% Cumulative Trust Preferred Securities and 12,371 shares of its common securities.

      Holders of shares of the Preferred Stock are entitled to receive cumulative annual cash dividends of $10 per share, payable quarterly in cash on each February 15, May 15, August 15 and November 15. Dividends are paid in arrears on the basis of a360-day year consisting of twelve30-day months. Dividends on the Preferred Stock accumulated from the date of issuance and compound quarterly. On May 15, 2005, the Company paid dividends on its Preferred Stock totaling approximately $0.6 million, or $1.66667 per share, and on both August 15, 2005, and November 15, 2005, the Company paid dividends totaling approximately $0.9 million, or $2.50 per share.

      The Preferred Stock is convertible at the holder’s option at any time at an initial conversion rate of 26.1428 shares of the Company’s Common Stock per $200 liquidation preference of shares, which represents an initial conversion price of approximately $7.65 per share of Common Stock. The Company may redeem the Preferred Stock for cash after February 20, 2010, at an initial redemption price equal to 100% of the liquidation preference, plus accumulated and unpaid dividends to the date of redemption. The Preferred Stock is mandatorily redeemable for cash on February 20, 2015, at a redemption price equal to 100% of the liquidation preference, plus accumulated and unpaid dividends to the date of redemption.

      If certain specified “fundamental changes” involving the Company occur prior to February 20, 2010, the Company may be required to pay a make-whole premium on the Preferred Stock converted in connection with the fundamental change. The make-whole premium will be payable in shares of the Company’s Common Stock or the consideration into which the Common Stock has been converted or exchanged in connection with the fundamental change. The amount of the make-whole premium, if any, will be based on the Common Stock price and the effective date of the fundamental change. A “fundamental change” involving the Company will be deemed to have occurred if (i) certain transactions occur as a result of which there is a change of control of the Company, or (ii) the Company’s Common Stock ceases to be listed on a national securities exchange or quoted on The Nasdaq National Market or another established automatedover-the-counter trading market in the United States.

     Registration Statements. On April 11, 2005, the Company filed a universal shelf registration statement on Form S-3 with the SEC to register an aggregate of $150 million of various securities, which was declared effective by the SEC on June 14, 2005. Subsequent to the effectiveness of this registration statement, the Company completed a Common Stock offering of $31.3 million under the shelf registration statement, leaving $118.7 million of securities available for possible future issuances under this registration statement. In

71

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Note 4. Capitalization (continued)

addition, and as discussed in more detail below, on May 26, 2005, the Company filed a resale shelf registration statement with the SEC, in compliance with its obligations under a registration rights agreement entered into at the time of the issuance of the Preferred Stock. This resale registration statement relates to the resale of shares of the Preferred Stock and to shares of Common Stock issuable upon conversion of the Preferred Stock and was declared effective by the SEC on August 12, 2005.

     Company Obligated Mandatorily Redeemable Trust Preferred Securities. The Company had Company-obligated mandatorily redeemable trust preferred securities that were issued by its capital trust subsidiaries (“Trust Preferred Securities”). These trusts were established for the sole purpose of issuing Trust Preferred Securities to the public and lending the gross proceeds, including the proceeds from the Company’s common equity investment, to the Company. The sole assets of the capital trusts were debt securities of the Company with terms similar to the terms of the related Trust Preferred Securities. The Trust Preferred Securities had characteristics of both debt and equity and for periods prior to July 1, 2003, they were reported in the Consolidated Statements of Financial Position as a separate line item between long-term debt and common shareholders’ equity. For periods after July 1, 2003, and before December 31, 2003, the Trust Preferred Securities were reflected in the long-term debt section of the Consolidated Statements of Financial Position in compliance with the provisions of SFAS 150. Prior to July 1, 2003, the dividends on these Trust Preferred Securities were reflected in the Consolidated Statements of Operations as “minority interest — dividends on Trust Preferred Securities.” In accordance with the provisions of SFAS 150, the dividends incurred on these securities during the period from July 1, 2003, through December 31, 2003, are reflected in “interest expense.” The adoption of SFAS 150 did not have a material impact on the Company’s net income (loss) available to common shareholders.

      On April 29, 2005, the Company used a portion of the proceeds it received from the issuance of its Preferred Stock to redeem $10.3 million of the 10.25% Subordinated Notes held by the Trust. Concurrently, the Trust used the proceeds it received from the redemption of the 10.25% Subordinated Notes to redeem 400,000 Trust Preferred Securities at a redemption price of $25.00 per security, for a total principal payment of $10.0 million. The Trust also used a portion of the proceeds to redeem $0.3 million of the Company’s common equity investment in the Trust, representing 12,371 common securities of the Trust.

      On September 14, 2005, the Company used the proceeds it received from the sale of 4,945,000 shares of its Common Stock to redeem the remaining $30.9 million of the 10.25% Subordinated Notes held by the Trust. Concurrently, the Trust used the proceeds it received from the redemption of the 10.25% Subordinated Notes to redeem the remaining 1.2 million Trust Preferred Securities at a redemption price of $25.00 per security, for a total principal payment of $30.0 million. The Trust also used a portion of the proceeds to redeem the remaining $0.9 million of the Company’s common equity investment in the Trust, representing 37,114 common securities of the Trust.

      As a result of redemptions during 2005, at December 31, 2005, the Company had no common equity investment in the trusts, the trusts had no outstanding Trust Preferred Securities, and the Company had no outstanding debt due to the trusts. At December 31, 2004, the Company had a $1.2 million common equity investment in these trusts, which was reflected in deferred charges and other assets in the Consolidated Statements of Financial Position and $41.3 million of debt securities due to the trusts, of which $41.2 million was reflected in long-term debt and $0.1 million was reflected in current maturities of long-term debt, in the Consolidated Statements of Financial Position. The trusts had $40.1 million of Trust Preferred Securities outstanding at December 31, 2004.

     Other Matters Regarding Trust Preferred Securities. During a portion of 2003, the Company had 10.1 million shares of FELINE PRIDES securities outstanding. Each FELINE PRIDES security consisted of a stock purchase contract and a 9% trust preferred security of SEMCO Capital Trust II with a stated face value per security of $10. Under the terms of each stock purchase contract, the FELINE PRIDES security holder was obligated to purchase from the Company, and the Company was obligated to sell to the FELINE

72

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Note 4. Capitalization (continued)

PRIDES security holder, between 0.7794 and 0.8651 shares of Company Common Stock in August 2003. The actual number of shares of Common Stock to be sold depended on the average market value of a share of Company Common Stock during a20-day period ending in August 2003.

      The FELINE PRIDES security holders were able to settle their obligation to purchase Company Common Stock by paying cash or by having their 9% trust preferred securities remarketed in August 2003. Approximately all of the FELINE PRIDES security holders elected to have their trust preferred securities remarketed to raise the cash needed to fulfill their obligations under the terms of the stock purchase contracts. The remarketing was not successful and the Company took possession of those trust preferred securities and retired them in order to satisfy the FELINE PRIDES security holders’ obligations to purchase 8.74 million shares of the Company’s Common Stock. The distribution rate on the 9% trust preferred securities was also reset in August 2003 to 3.77%.

     Long-Term Debt. In November 2005, the Company’s $15.0 million of outstanding 6.5% Senior Notes matured and were redeemed at par. The Company utilized its Bank Credit Agreement to finance this redemption. For further information on the Bank Credit Agreement, refer to Note 5 of the Notes to the Consolidated Financial Statements.

      On April 29, 2005, the Company redeemed $10.3 million of the 10.25% Subordinated Notes held by the Trust. On September 14, 2005, the Company redeemed the remaining $30.9 million of the 10.25% Subordinated Notes held by the Trust. The redemptions were funded from proceeds received from the sale of Preferred Stock and Common Stock in 2005, as previously discussed in this Note under the caption “Company Obligated Mandatorily Redeemable Trust Preferred Securities.”

      In June 2004, the Company redeemed all $29.9 million of its outstanding 8% Senior Notes due 2010 at par. The Company utilized a portion of the net proceeds received from the issuance of CPS, as previously discussed, to redeem these notes.

      In January 2004, the Company entered into an interest rate swap agreement with a financial institution in order to hedge $50 million of its $150 million 7.125% senior unsecured notes due 2008. The swap agreement, which covers these notes through maturity, effectively converts the fixed interest rate on these notes to a floating interest rate and is being accounted for as a fair value hedge. On a semi-annual basis, the Company pays the counterparty a floating interest rate based on LIBOR plus a spread of 375 basis points and receives payments based on a fixed interest rate of 7.125%. Refer to Note 7 for additional information.

      In December 2003, the Company completed an offering of an aggregate of $50 million of 7.75% senior unsecured notes due 2013 (“7.75% 2013 Notes”). The notes are of the same class as notes issued by the Company in May 2003, as discussed below. The $50 million in notes were issued at a premium of $2.1 million. The issuance was done concurrently with an amendment of the Company’s then-existing bank credit facility and the proceeds from this issuance were used to repay indebtedness under that bank credit facility.

      In May 2003, the Company completed an offering of an aggregate of $300 million of senior unsecured notes. The offering consisted of $150 million of 7.125% senior unsecured notes due 2008 (“7.125% 2008 Notes”) and $150 million of 7.75% 2013 Notes. Interest on these notes is payable semiannually. The Company used approximately $92.3 million of the 7.75% 2013 Notes in an exchange for $77 million of its outstanding 8.95% Remarketable or Redeemable Securities (“ROARS”). After the exchange was completed, the Company cancelled the $77 million of ROARS. The Company accounted for the debt exchange under the provisions of Emerging Issues Task Force Opinion No. 96-19 (“EITF 96-19”). In accordance with EITF 96-19, the Company used the book value of the ROARS ($77 million) as the initial book value for the $92.3 million of 7.75% 2013 Notes issued in the exchange. The difference between the face amount and the initial book value of the 7.75% 2013 Notes will be amortized as interest expense, using the effective interest method, over the life of the notes. As a result, the book value of the 7.75% 2013 Notes will increase by the amount of amortization expense recognized over the life of the notes. The exchange of the $92.3 million of

73

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Note 4. Capitalization (continued)

7.75% 2013 Notes for the $77 million of ROARS was a non-cash financing activity. As a result, it is not reflected in the Company’s Consolidated Statements of Cash Flows.

      The Company used a portion of the proceeds from the issuance of the $300 million of notes in 2003 to repurchase its $55 million of outstanding 8.00% Senior Notes due 2004, $30 million of outstanding 7.2% Senior Notes due 2007, $25 million of outstanding 8.32% Senior Notes due 2024 and the remaining $28 million of ROARS plus accrued interest. Approximately $24 million of the proceeds was used to pay make-whole premiums or similar items in connection with the repurchase of the $138 million in notes and securities. The make-whole premiums or similar items were incurred, in most instances, in order to repurchase these obligations prior to their maturity. The Company expensed the $24 million at the time of the refinancing. The remainder of the proceeds was used to pay expenses associated with the issuance of the new notes (approximately $10.1 million), to pay down short-term debt and for working capital and general corporate purposes.

      At December 31, 2005, there were no annual sinking fund requirements for the Company’s existing debt over the next five years. The Company has $185 million of long-term debt maturing over the next five years as follows (in millions):

2006	$	—
2007	$	—
2008	$	155
2009	$	30
2010	$	—

Note 5. Short-Term Borrowings

      In September 2005, the Company entered into an amended and restated three-year unsecured revolving bank credit facility for $120 million, which expires on September 15, 2008 (the “Bank Credit Agreement”). The Bank Credit Agreement amends and restates the Company’s previous short-term bank credit facility, which consisted of a $60 million multi-year revolving facility and a $40.8 million364-day facility, both of which were due to expire on September 23, 2005. Interest under the terms of the Bank Credit Agreement is at variable rates, which are based on LIBOR or prime lending rates, plus applicable margins. LIBOR-based borrowings are permitted for periods ranging from two weeks to one, two, three or six months. At December 31, 2005, the Company was utilizing $95.7 million of the borrowing capacity available under the Bank Credit Agreement, leaving approximately $24.3 million of the borrowing capacity unused. The $95.7 million of capacity being used consisted of $16.8 million of outstanding letters of credit and $78.9 million of outstanding borrowings.

	Years Ended December 31,
	2005			2004			2003
	(In thousands)
Notes payable balance at year end	$	78,900		$	39,300		$	82,034
Unused lines of credit at year end	$	24,277		$	61,914		$	38,275
Average interest rate at year end		6.1	%		4.9	%		3.4	%
Highest borrowings at any month-end	$	89,300		$	65,203		$	124,468
Average borrowings	$	15,795		$	14,477		$	92,138
Weighted average interest rate		5.6	%		3.6	%		3.0	%

      Covenants in the Company’s Bank Credit Agreement require maintenance at the end of each calendar quarter of a minimum consolidated net worth of $225.0 million, adjusted annually by 50% of consolidated net income, if positive, plus 100% of the proceeds of each new capital offering conducted by the Company or any

74

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Note 5. Short-Term Borrowings (continued)

of its subsidiaries on or after June 30, 2005, net of issuance costs, less the aggregate principal amount of any junior capital which is retired, prepaid or redeemed in connection with a new capital offering (at December 31, 2005, the required minimum net worth was $225.0 million). In addition, the Bank Credit Agreement requires the Company to maintain, at the end of each fiscal quarter, a minimum interest coverage ratio of not less than 1.25 to 1 through September, 30, 2007, and not less than 1.30 to 1 thereafter, and a maximum leverage ratio of not more than 65%. As of December 31, 2005, the Company was in compliance with these Bank Credit Agreement covenants. The Company’s failure to comply with any of its financial covenants may result in an event of default which, if not cured or waived, could result in the acceleration of the debt under the Bank Credit Agreement or the indentures governing its outstanding debt issuances that contain cross-acceleration or cross-default provisions. In such a case, there can be no assurance that the Company would be able to refinance or otherwise repay such indebtedness, which could result in a material adverse effect on its business, results of operation, liquidity and financial condition.

Note 6. Financial Instruments

      The following methods and assumptions were used to estimate the fair value of each significant class of financial instruments:

     Cash, Cash Equivalents, Accounts Receivables, Payables and Notes Payable. The carrying amount approximates fair value because of the short maturity of those instruments.

     Long-Term Debt. The fair values of the Company’s long-term debt are estimated based on quoted market prices for the same or similar issues. The table below shows the estimated fair values of the Company’s long-term debt as of December 31, 2005, and 2004.

		December 31,
		2005		2004
		(In thousands)
Long-term debt, including current maturities
	Carrying amount	$	441,659	$	498,427
	Fair value		471,967		548,060

Note 7. Risk Management Activities and Derivative Transactions

      The Company’s business activities expose it to a variety of risks, including commodity price risk and interest rate risk. The Company’s management identifies risks associated with the Company’s business and determines which risks it wants to manage with financial instruments and which type of instruments it should use to manage those risks.

      The Company records all derivative instruments it enters into under the provisions of SFAS 133, “Accounting for Derivative Instruments and Hedging Activities,” and SFAS 137, SFAS 138 and SFAS 149, which were amendments to SFAS 133 (hereinafter collectively referred to as “SFAS 133”). SFAS 133 requires that every derivative instrument (including certain derivative instruments embedded in other contracts) be recorded in the statement of financial position, as either an asset or liability, measured at its fair value. SFAS 133 also requires that changes in the derivative’s fair value be recognized currently in earnings unless specific hedge accounting criteria are met. Special accounting for qualifying hedges allows a derivative’s gains and losses to offset related results on the hedged item in the statement of operations, and requires that a company must formally document, designate, and assess the effectiveness of transactions that receive hedge accounting. For derivatives designated as cash flow hedges, changes in fair value are recorded in comprehensive income for the portion of the change in value of the derivative that is an effective hedge.

      An affiliate in which the Company has a 50% ownership interest (Eaton Rapids Gas Storage System or “ERGSS”) uses afloating-to-fixed interest rate swap agreement to hedge the variable interest rate payments

75

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Note 7. Risk Management Activities and Derivative Transactions (continued)

on a portion of its long-term debt. This swap is designated as a cash flow hedge and the difference between the amounts paid and received under the swap is recorded as an adjustment to interest expense over the term of the agreement. The Company’s share of changes in the fair value of the swap are recorded in accumulated other comprehensive income until the swap is terminated. As a result of this interest rate swap agreement, the Company’s Consolidated Statements of Financial Position, at December 31, 2005, and December 31, 2004, reflected reductions of $0.03 million and $0.2 million, respectively, in the Company’s equity investment in ERGSS and in accumulated comprehensive income.

      The Company may, from time to time, enter intofixed-to-floating interest rate swaps in order to maintain its desired mix of fixed-rate and floating-rate debt. These swaps are designated as fair value hedges and the difference between the amounts paid and received under these swaps is recorded as an adjustment to interest expense over the term of the swap agreement. If the swaps are terminated, any unrealized gains or losses are recognized pro-rata over the remaining term of the hedged item as an increase or decrease in interest expense. The Company entered into one such interest rate swap in January 2004 in order to hedge one-third of its $150 million 7.125% 2008 Notes. This agreement qualifies under the provisions of SFAS 133 as a fair value hedge. In accordance with SFAS 133, the Company’s Consolidated Statements of Financial Position at December 31, 2005, included a liability of $1.7 million and a decrease in long-term debt of $1.7 million related to this interest rate swap. At December 31, 2004, the Company’s Consolidated Statements of Financial Position included a liability of $0.5 million and a decrease in long-term debt of $0.5 million related to this interest rate swap.

Note 8. Pension Plans and Other Postretirement Benefits

     Pensions. The Company has defined benefit pension plans for eligible employees. Pension plan benefits are generally based upon years of service or a combination of years of service and compensation during the final years of employment. The Company’s funding policy is to contribute amounts annually to the plans based upon actuarial and economic assumptions intended to achieve adequate funding of projected benefit obligations. The Company also has a supplemental executive retirement plan (“SERP”), which is an unfunded defined benefit pension plan.

      The total additional minimum pension liability at December 31, 2005, was $14.5 million. The total accumulated benefit obligation for the Company’s pension plans was $84.4 million at December 31, 2005. The Company contributed $5.7 million to its pension plans during 2005. The Company estimates it will contribute $5.4 million to its pension plans in 2006 and, therefore, $5.4 million of the Company accrued pension cost is reflected in other current liabilities in the Company’s Consolidated Statement of Financial Position at December 31, 2005.

     Other Postretirement Benefits. The Company has postretirement benefit plans that provide certain medical and prescription drug benefits to eligible retired employees, their spouses and covered dependents. Determination of benefits is based on a combination of the retiree’s age and years of service at retirement. The Company accounts for retiree medical benefits in accordance with SFAS 106, “Employers’ Accounting for Postretirement Benefits Other Than Pensions.” This standard requires the full accrual of such costs during the years that the employee renders service to the Company until the date of full eligibility.

      In 2005, 2004 and 2003, the Company expensed retiree medical costs of $1.0 million, $1.2 million and $2.8 million, respectively. The retiree medical expense for each of those years includes $0.9 million of amortization of previously deferred retiree medical costs. Prior to getting regulatory approval for the recovery of retiree medical benefits in rates, the Company deferred, as a regulatory asset, any portion of retiree medical expense that was not yet provided for in customer rates. After receiving rate approval for recovery of such costs, the Company began amortizing, as retiree medical expense, the amounts previously deferred. The Company, as a matter of practice, has paid retiree medical costs from its corporate assets. During 2005, the Company paid $1.7 million from its corporate assets, net of participant contributions, to cover retiree medical

76

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Note 8. Pension Plans and Other Postretirement Benefits (continued)

costs. The Company estimates it will pay $1.7 million from its corporate assets or its funded postretirement benefit plans in 2006 to cover retiree medical costs. As a result, $1.7 million of the Company’s accrued other postretirement benefit cost is reflected in other current liabilities in the Company’s Consolidated Statement of Financial Position at December 31, 2005.

		Years Ended December 31,
		Pension Benefits									Other Postretirement Benefits
		2005			2004			2003			2005			2004			2003
		(In thousands)
Components of net benefit cost
	Service cost	$	2,922		$	2,387		$	1,865		$	467		$	362		$	355
	Interest cost		4,899			4,508			4,299			1,860			1,859			2,447
	Expected return on plan assets		(5,460	)		(5,072	)		(4,812	)		(2,163	)		(1,910	)		(1,647	)
	Amortization of transition obligation		—			2			23			69			69			413
	Amortization of prior service cost		108			173			118			(286	)		(286	)		(59	)
	Amortization of net (gain) or loss		2,497			1,487			1,065			198			200			423
	Amortization of regulatory asset		—			—			—			899			899			899
Net benefit cost		$	4,966		$	3,485		$	2,558		$	1,044		$	1,193		$	2,831

      The Company has certain Voluntary Employee Benefit Association (“VEBA”) trusts to fund its retiree medical benefits. There were no contributions to the VEBA trusts during 2005, 2004 and 2003. The Company can also partially fund retiree medical benefits on a discretionary basis through Internal Revenue Code Section 401(h) accounts. No cash contributions were made to the 401(h) accounts in 2005, 2004 and 2003.

      The Company uses a measurement date of December 31 for all of its plans. The following tables provide reconciliations of the plan benefit obligations, plan assets, funded status of the plans and additional information related to the Company’s benefit obligations.

								Other Postretirement
		Pension Benefits						Benefits
		2005			2004			2005			2004
		(In thousands)
Change in benefit obligation
	Benefit obligation at January 1	$	82,227		$	72,831		$	34,409		$	40,033
	Service cost		2,922			2,387			467			362
	Interest cost		4,899			4,508			1,860			1,859
	Actuarial (gain) loss		8,122			5,996			1,074			(1,542	)
	Benefits paid from plan assets		(3,527	)		(4,260	)		—			—
	Benefits paid from corporate assets, net of participant contributions		—			—			(1,677	)		(829	)
	Plan amendments		202			765			—			(5,474	)
	Benefit obligation at December 31	$	94,845		$	82,227		$	36,133		$	34,409

77

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Note 8. Pension Plans and Other Postretirement Benefits (continued)

								Other Postretirement
		Pension Benefits						Benefits
		2005			2004			2005			2004
		(In thousands)
Change in plan assets
	Fair value of plan assets at January 1	$	63,454		$	54,936		$	25,449		$	22,474
	Actual return on plan assets		4,043			5,440			1,729			2,975
	Company contributions		5,742			7,338			—			—
	Benefits paid from plan assets		(3,527	)		(4,260	)		—			—
	Fair value of plan assets at December 31	$	69,712		$	63,454		$	27,178		$	25,449
Reconciliation of funded status of the plans
	Funded (unfunded) status	$	(25,133	)	$	(18,773	)	$	(8,955	)	$	(8,960	)
	Unrecognized net (gain) loss		33,101			26,060			5,828			4,518
	Unrecognized prior service cost		898			804			(2,273	)		(2,559	)
	Unrecognized net transition obligation		—			—			483			552
	Additional minimum pension liability		(14,547	)		(11,514	)		—			—
	Total liability at December 31	$	(5,681	)	$	(3,423	)	$	(4,917	)	$	(6,449	)
Amounts recognized in statements of financial position consist of:
	Prepaid benefit cost	$	8,866		$	8,091		$	—		$	—
	Accrued benefit cost		—			—			(4,917	)		(6,449	)
	Intangible asset		(456	)		(302	)		—			—
	Accumulated comprehensive income		(14,091	)		(11,212	)		—			—
	Total liability at December 31	$	(5,681	)	$	(3,423	)	$	(4,917	)	$	(6,449	)
Information for pension plans with an accumulated benefit obligation in excess of plan assets at December 31
	Accumulated benefit obligation	$	51,320		$	45,359			n/a			n/a
	Fair value of plan assets	$	36,078		$	34,927			n/a			n/a
Information for pension and postretirement benefit plans with a projected benefit obligation in excess of plan assets at December 31
	Projected benefit obligation	$	84,096		$	73,285		$	22,267		$	21,180
	Fair value of plan assets	$	58,769		$	54,284		$	12,182		$	11,422
Accumulated benefit obligation for all plans at December 31		$	84,418		$	73,322			n/a			n/a
Additional information
	Increase (decrease) in minimum liability included in other comprehensive income	$	2,880		$	1,201			n/a			n/a

78

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Note 8. Pension Plans and Other Postretirement Benefits (continued)

     Assumptions. The following tables provide the assumptions used to determine the benefit obligations and the net periodic benefit costs for the Company’s pension plans and other postretirement benefit plans.

									Other Postretirement
			Pension Benefits						Benefits
			2005			2004			2005			2004
			(In thousands, except for percentages)
Weighted average assumptions used to determine net periodic benefit cost for years ended December 31
	Discount rate			5.75	%		6.25	%		5.75	%		6.25	%
	Expected long-term rate of return on plan assets			8.50	%		8.50	%		8.50	%		8.50	%
	Rate of compensation increase			4.00	%		4.00	%		n/a			n/a
Weighted average assumptions used to determine benefit obligations at December 31
	Discount rate			5.50	%		5.75	%		5.50	%		5.75	%
	Rate of compensation increase			4.00	%		4.00	%		n/a			n/a
Assumed health care cost trend rate
	Medical
		Rate assumed for next year		n/a			n/a			8.00	%		8.00	%
		Rate to which cost trend rate is assumed to decline (the ultimate trend rate)		n/a			n/a			5.00	%		5.00	%
		Year of ultimate trend rate		n/a			n/a			2013			2010
	Prescription drug
		Rate assumed for next year		n/a			n/a			10.00	%		12.00	%
		Rate to which cost trend rate is assumed to decline (the ultimate trend rate)		n/a			n/a			5.00	%		5.00	%
		Year of ultimate trend rate		n/a			n/a			2013			2010
Effect of a 1% increase in health cost trend rate
	Effect on accumulated postretirement benefit obligation			n/a			n/a		$	5,734		$	5,161
	Effect on aggregate of service and interest costs			n/a			n/a		$	412		$	362
Effect of a 1% decrease in health cost trend rate
	Effect on accumulated postretirement benefit obligation			n/a			n/a		$	(4,658	)	$	(4,219	)
	Effect on aggregate of service and interest costs			n/a			n/a		$	(327	)	$	(290	)

      The discount rate used by the Company is determined by reference to the CitiGroup pension discount curve, other long-term corporate bond measures and the expected cash flows of the plans. The duration of the securities underlying those indexes reasonably matches the expected timing of anticipated future benefit payments.

      The expected long-term rate of return on plan assets is established based on the Company’s expectations of asset returns for the investment mix in its plans (with some reliance on historical asset returns for the plans). The expected returns of various asset categories are blended to derive an appropriate long-term assumption.

79

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Note 8. Pension Plans and Other Postretirement Benefits (continued)

     Plan Assets. The weighted-average asset allocations of the Company’s pension plans and its other postretirement benefit plans at December 31, 2005, and 2004 are presented in the following table:

		Percentage Allocation
								Other
								Postretirement
		Pension Benefits						Benefits
December 31,		2005			2004			2005			2004
Asset Category
	Equity securities		65.0	%		67.5	%		65.0	%		61.9	%
	Debt securities		25.9	%		25.6	%		35.0	%		35.2	%
	Other		9.1	%		6.9	%		0.0	%		2.9	%
	Total		100.0	%		100.0	%		100.0	%		100.0	%

      The Company has a target asset allocation of 70% equities and 30% debt instruments for its pension plans. This does not include certain insurance contracts for retirees. Year-end pension contributions and cash held for retiree pension payments also impact the actual allocation compared to the target allocation. The other postretirement benefit plans have a target allocation of 60% equities and 40% debt and other instruments. The other instruments portion of this allocation consists of a life-insurance product, which was surrendered in 2005, with the proceeds reallocated to other assets within the VEBA trusts.

      The primary goal of the Company’s retirement plan investment approach is to ensure that pension and other postretirement liabilities are met. An emphasis is placed on the long-term characteristics of individual asset classes, and the benefits of diversification across multiple asset classes. The approach incorporates an assessment of the proper long-term level of risk for the plans, considering factors such as the long-term nature of the plans’ liabilities, the current funded status of the plans, and the impact of asset allocation on the volatility and magnitude of the plans’ contributions and expense.

     Estimated Future Benefit Payments. The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid.

			Other Postretirement Benefits
	Pension		Gross		Less Medicare Part D		Net
	Benefits		Benefits		Subsidy		Benefits
	(In thousands)
2006	$	3,600	$	1,900	$	200	$	1,700
2007		3,800		1,900		200		1,700
2008		3,800		1,900		200		1,700
2009		4,300		2,000		200		1,800
2010		4,800		2,100		200		1,900
Years 2011 - 2015		28,100		11,900		1,500		10,400

     401(K) Plans and Profit Sharing Plans. The Company has defined contribution plans, commonly referred to as 401(k) plans, covering eligible employees. Certain of the 401(k) plans contain provisions for Company matching contributions. The amount expensed for the Company match provisions was $1.2 million for 2005 and $1.1 million for both years 2004 and 2003.

      The Company has profit sharing plans covering certain employees. Annual contributions are generally discretionary or determined by a formula, which contains minimum contribution requirements. Profit sharing expense was $0.3 million for 2005 and $0.2 million for both years 2004 and 2003.

80

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Note 9. Share-Based Compensation

      At the Company’s 2004 Annual Meeting, shareholders approved the 2004 Stock Award and Incentive Plan (“2004 Plan”), which provides for, in various forms, the issuance of up to 1,500,000 shares of Common Stock plus any shares which become available through forfeiture or through other prescribed means from the Company’s previous long-term incentive or stock option plans after the effective date of the 2004 Plan. Awards may be in the form of stock options, stock appreciation rights, restricted stock, deferred stock, bonus stock and awards in lieu of obligations, dividend equivalents, other share-based awards, or performance awards. Awards granted thus far under the 2004 Plan have been in the form of (i) stock options, (ii) performance share units and restricted stock units, and (iii) restricted stock. These awards are discussed in greater detail below.

      The Company also has a deferred compensation plan for its Board and an employee stock gift program. The deferred compensation plan allows for the deferral of Board member compensation, at the Board member’s election, that can be invested in the Company’s Common Stock. Any deferral of Board member compensation is expensed in the Company’s Consolidated Statement of Operations when earned by the Board member. The employee stock gift program provides one free share of Company Common Stock to an employee the first time he or she enrolls in the Company’s program to make contributions to the Company’s DRIP via employee payroll deductions.

      At December 31, 2005, there were 966,168 share-based awards available for grant to employees and Board members under the plans discussed above.

     Restricted Stock Units for Executives. During 2005 and 2004, the Company issued 22,228 and 92,500 restricted stock units (“RSUs”), respectively, with weighted average fair values of $6.50 and $5.63, respectively, based on the market price of the Company’s Common Stock on the dates of grant. Each RSU is equivalent to one share of Company Common Stock. 10,000 of the RSUs issued in 2004 have been forfeited because the individual to whom the RSUs were issued is no longer employed by the Company. 14,728 of the RSUs issued in 2005 vest in full on the three-year anniversary of issuance as long as the individual who received the RSUs remains employed on the vesting date. The remaining 90,000 outstanding RSUs vest at different dates over the period from issuance to March 31, 2007. Approximately 42% of these remaining 90,000 RSUs vest in full on approximately the one-year anniversary of issuance as long as the individuals who received the RSUs remain employed on the vesting date. Approximately 29% of these remaining 90,000 RSUs vest in 2006 and the remaining 29% vest in 2007, subject to the attainment of certain performance targets as long as the individuals remain employed on the vesting dates. Notwithstanding these vesting conditions, the RSUs vest in their entirety upon a change in control of the Company. Settlement of the vested RSUs will be made in shares of the Company’s Common Stock. There were 69,728, and 92,500 non-vested RSUs outstanding at December 31, 2005 and 2004, respectively.

     Employee Performance Share Units.During 2005, the Company issued 168,667 performance share units (“PSUs”) at target (“Target Grant”). Each PSU is equivalent to one share of Company Common Stock. The PSUs have a weighted average fair value of $6.15, based on the market price of the Company’s Common Stock on the date of grant. Under the terms of the PSUs, the grantee can vest in PSUs equivalent to 25% to 150% of the Target Grant if actual performance results are within 25% to 150% of the target performance goals. Following a three-year performance period for 143,667 of the PSUs and a two-year performance period for 25,000 of the PSUs, a percentage of PSUs will vest if the individuals who received the PSUs are actively employed with the Company on the last day of the performance period and if the threshold level of performance is met or exceeded with respect to at least one of the established performance goals. Notwithstanding these vesting conditions, the PSUs vest in their entirety upon a change in control of the Company. Settlement of vested PSUs will be made in shares of the Company’s Common Stock. There were 168,667 non-vested PSUs outstanding at December 31, 2005.

     Restricted Stock for Directors.During 2005, the Company issued 176,583 shares of restricted stock to non-employee Directors with a weighted average fair value of $5.83, based on the market price of the Company’s Common Stock on the dates of grant. The restrictions on 7,833 of those shares were waived due to

81

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Note 9. Share-Based Compensation (Continued)

the immediate retirement of the individuals who were granted those shares. The remaining restricted stock vests over a three-year period as long as the individuals who received the restricted stock continue to serve on the Company’s Board on the vesting dates. Notwithstanding these vesting conditions, the restricted stock for Directors vests in its entirety upon a change in control of the Company. At December 31, 2005, there were 168,750 shares of non-vested restricted stock outstanding.

     Options to Purchase Common Stock. The exercise price of all options granted is equal to the average of the high and low market price on the options grant date. The options vest over the three-year period following the date of grant and expire ten years from the date of grant. Both the number of options granted and the exercise price are adjusted for any stock dividends and stock splits occurring during the life of the options. The fair values of the options were estimated at the grant date using a Black-Scholes option pricing model and the weighted average assumptions shown in the table below:

	2005			2004			2003
Risk-free interest rate		3.95	%		3.44	%		2.91	%
Dividend yield		0.00	%		0.26	%		8.21	%
Volatility		39.32	%		43.35	%		41.81	%
Average expected term (years)		5			5			5
Fair value of options granted	$	2.59		$	2.20		$	0.52

      The following table summarizes information concerning outstanding and exercisable options at December 31, 2005:

	Options Outstanding						Options Exercisable
					Weighted				Weighted
			Remaining		Average				Average
	Number		Contractual Life in		Exercise		Number		Exercise
Range of Exercisable Prices	Outstanding		Years		Price ($)		Exercisable		Price ($)
$ 4.13 - $ 5.64		406,267		8.2		5.15		191,074		4.91
$ 5.78 - $ 7.43		413,113		7.6		6.66		231,777		7.16
$ 9.99 - $14.26		193,000		4.9		13.52		193,000		13.52
$14.35 - $17.14		146,979		3.6		15.42		146,979		15.42
		1,159,359						762,830

82

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Note 9. Share-Based Compensation (Continued)

      The following table shows the stock option activity during the past three years and the number of stock options exercisable under the Company’s plans at the end of each such year:

		Number of			Weighted Average
		Shares			Exercise Price ($)
Outstanding at December 31, 2002			1,139,218			12.96
	Granted		184,285			4.29
	Exercised		—			—
	Canceled		(145,768	)		11.99
Outstanding at December 31, 2003			1,177,735			11.72
	Granted		419,800			5.51
	Exercised		(2,668	)		4.13
	Canceled		(302,825	)		11.66
Outstanding at December 31, 2004			1,292,042			9.73
	Granted		136,813			6.11
	Exercised		(2,333	)		4.13
	Canceled		(267,163	)		13.78
Outstanding at December 31, 2005			1,159,359			8.38
Exercisable at December 31, 2003			781,208			13.81
Exercisable at December 31, 2004			857,523			11.92
Exercisable at December 31, 2005			762,830			9.80

      For further information regarding stock-based compensation, refer to the caption “Share-Based Compensation” in Note 1.

Note 10. Earnings Per Share

      The Company computes earnings per share (“EPS”) in accordance with SFAS 128, “Earnings per Share.” SFAS 128 requires the computation and presentation of two EPS amounts, basic and diluted. Basic EPS is computed by dividing income available to holders of Common Stock by the weighted average number of common shares outstanding during the period. The computation of diluted EPS is similar to that of basic EPS except that the weighted average number of common shares outstanding is increased to include any shares that would be available if outstanding stock options were exercised, shares of Preferred Stock and CPS were converted to shares of Common Stock, shares of non-vested restricted stock were fully vested, and stock purchase contracts, RSUs and PSUs were settled in shares of Common Stock. However, the diluted EPS calculation does not include these potential shares in instances when their inclusion in the diluted EPS calculation results in an EPS figure that is anti-dilutive when compared to basic EPS.

83

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Note 10. Earnings Per Share (continued)

      The following table indicates the potential dilutive impact of the Company’s dilutive securities on average Common Stock shares outstanding and potential adjustments to the Company’s Consolidated Statements of Operations when computing diluted EPS:

		Years Ended December 31,
		2005		2004		2003
		(In thousands)
Potential dilutive impact on average common shares outstanding when calculating diluted earnings per share
	Assumed conversion of convertible cumulative preferred stock		7,283		—		—
	Assumed conversion of convertible preference stock		1,614		5,430		—
	Assumed exercise of stock options		55		24		20
	Assumed settlement of restricted stock units and performance share units		13		9		—
	Assumed vesting of non-vested restricted stock		16		—		—
	Assumed failed remarketing and assumed retirement of trust preferred securities		—		—		5,280
Potential income statement adjustments when calculating diluted earnings per share
	Eliminate dividends on convertible cumulative preferred stock assumed converted	$	2,994	$	—	$	—
	Eliminate dividends and repurchase premium on convertible preference stock assumed converted	$	9,112	$	3,203	$	—
	Eliminate dividends on trust preferred securities assumed retired	$	—	$	—	$	5,681

84

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Note 10. Earnings Per Share (continued)

      The following table outlines the computations of basic and diluted EPS. The potential adjustments indicated in the previous table are not included in the following computations of diluted EPS if their impact for a given period is anti-dilutive when compared to basic EPS for the period:

			Years Ended December 31,
			2005			2004			2003
			(In thousands, except per share
			amounts)
Average common shares outstanding
	Issued			30,470			28,263			22,297
	Adjustments to reconcile to average common shares outstanding for purposes of computing basic EPS:
		Subtract non-vested restricted stock		(83	)		—			—
		Add shares issuable under fully vested restricted stock units		21			—			—
	As adjusted — basic			30,408			28,263			22,297
	Adjustments to reconcile to average common shares outstanding for purposes of computing diluted EPS:
		Assumed conversion of convertible cumulative preferred stock		—			—			—
		Assumed conversion of convertible preference stock		—			—			—
		Assumed exercise of stock options		—			24			—
		Assumed settlement of restricted stock units and performance share units		—			9			—
		Assumed vesting of non-vested restricted stock		—			—			—
		Assumed failed remarketing and assumed retirement of trust preferred securities		—			—			—
	Diluted			30,408			28,296			22,297
Income (loss) from continuing operations
	As reported		$	11,737		$	4,156		$	(5,084	)
	Adjustments to reconcile to income (loss) from continuing operations for purposes of computing basic EPS:
		Subtract dividends and repurchase premium on convertible preference stock		(9,112	)		(3,203	)		—
		Subtract dividends on convertible cumulative preferred stock		(2,994	)		—			—
	As adjusted — basic		$	(369	)	$	953		$	(5,084	)
	Adjustments to reconcile to income (loss) from continuing operations for purposes of computing diluted EPS:
		Eliminate dividends on convertible cumulative preferred stock assumed converted		—			—			—
		Eliminate dividends and repurchase premium on convertible preference stock assumed converted		—			—			—
	Diluted		$	(369	)	$	953		$	(5,084	)
Earnings per share from income (loss) from continuing operations
	Basic		$	(0.01	)	$	0.03		$	(0.23	)
	Diluted		$	(0.01	)	$	0.03		$	(0.23	)
Income (loss) from discontinued operations
	As reported — basic		$	538		$	(9,339	)	$	(24,871	)
	Diluted		$	538		$	(9,339	)	$	(24,871	)
Earnings per share from income (loss) from discontinued operations
	Basic		$	0.02		$	(0.33	)	$	(1.11	)
	Diluted		$	0.02		$	(0.33	)	$	(1.11	)
Net income (loss) available to common shareholders
	As reported — basic		$	169		$	(8,386	)	$	(29,955	)
	Adjustments to reconcile to net income (loss) available to common shareholders for purposes of computing diluted EPS:
		Eliminate dividends on convertible cumulative preferred stock assumed converted		—			—			—
		Eliminate dividends and repurchase premium on convertible preference stock assumed converted		—			—			—
		Eliminate dividends on trust preferred securities assumed retired		—			—			—
	Diluted		$	169		$	(8,386	)	$	(29,955	)
Earnings per share from net income (loss) available to common shareholders
	Basic		$	0.01		$	(0.30	)	$	(1.34	)
	Diluted		$	0.01		$	(0.30	)	$	(1.34	)

85

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Note 11. Business Segments

      The Company follows SFAS 131,“Disclosure about Segments of an Enterprise and Related Information,” which specifies standards for reporting information about operating segments (“business segments”) in annual financial statements and requires selected information in interim financial statements. Business segments are defined as components of an enterprise about which separate financial information is available that is evaluated regularly by the chief operating decision maker, or decision-making group, to make decisions on how to allocate resources and to assess performance. The Company’s chief operating decision-making group is the Chief Executive Officer (“CEO”) and certain other executive officers who report directly to the CEO. The Company evaluates the performance of its business segments based on the operating income generated. Operating income does not include income taxes, interest expense, discontinued operations, and non-operating income and expense items.

      The Company has one reportable business segment: Gas Distribution. Under SFAS 131, a business segment that does not exceed certain quantitative levels is not considered a reportable business segment. Instead, business segments that do not exceed the quantitative thresholds are combined and reported in a separate category with other business activities that do not meet the definition of a business segment. The Company refers to this other category as “Corporate and Other.” For a description of the Company’s Gas Distribution segment, a description of the Company’s non-separately reportable business segments included in Corporate and Other, and information regarding the sale of the discontinued construction services segment in September 2004, refer to Note 1. The accounting policies of the Company’s business segments are the same as those described in Note 1 except that intercompany transactions have not been eliminated in determining individual segment results.

      The Company’s corporate division is a cost center rather than a business segment. Any corporate operating expenses that do not relate to the ongoing operations of the Company’s business segments or are not allocable to them under various regulatory rules are not allocated to those segments. Instead, these unallocated expenses remain on the books of the corporate division. The corporate division is included in Corporate and Other.

86

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Note 11. Business Segments (continued)

      The following table provides business segment information as well as a reconciliation of the segment information to the applicable line in the consolidated financial statements:

			Years Ended December 31,
			2005			2004			2003
			(In thousands)
Operating revenues
	Gas distribution		$	606,315		$	498,249		$	462,889
	Corporate and other			16,379			17,152			17,220
	Reconciliation to consolidated financial statements
	Intercompany eliminations(a)			(7,592	)		(7,065	)		(7,154	)
		Consolidated operating revenues	$	615,102		$	508,336		$	472,955
Depreciation and amortization
	Gas distribution		$	26,825		$	25,925		$	25,528
	Corporate and other			1,399			1,653			1,920
		Consolidated depreciation and amortization	$	28,224		$	27,578		$	27,448
Operating income (loss)
	Gas distribution		$	57,964		$	52,760		$	59,222
	Corporate and other			1,540			(7,275	)		1,475
		Consolidated operating income	$	59,504		$	45,485		$	60,697
Capital investments
	Gas distribution(b)		$	41,815		$	37,924		$	28,323
	Corporate and other			1,417			954			840
	Construction services(c)			—			34			1,003
		Consolidated capital investments	$	43,232		$	38,912		$	30,166
Assets at year end
	Gas distribution		$	966,835		$	864,183
	Corporate and other			49,720			62,015
		Consolidated assets at year end	$	1,016,555		$	926,198

(a)	Includes the elimination of intercompany gas distribution revenue of $209, $199 and $174 for 2005, 2004 and 2003. Includes the elimination of intercompany corporate and other revenue of $7,383, $6,866 and $6,980 for 2005, 2004 and 2003, respectively.
(b)	Gas Distribution capital investments for 2005 include $3,076 for a business acquisition.

(c) Effective January 1, 2004, the Company began accounting for the construction services segment as a discontinued operation. Accordingly, it’s operating results are segregated and reported as discontinued operations in the Consolidated Statements of Operations.

Note 12. Investments in Affiliates

      The equity method of accounting is used for interests where the Company has significant influence, but does not control an entity. The Company has a 50% ownership interest in ERGSS that it accounts for using the equity method of accounting. The investment in ERGSS is reported in deferred charges and other assets in the Consolidated Statements of Financial Position. ERGSS provides natural gas storage services to the Company’s Gas Distribution Business. ERGSS had annual operating revenues associated with services

87

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Note 12. Investments in Affiliates

provided to the Gas Distribution Business of $3.2 million, $3.4 million and $3.2 million in 2005, 2004 and 2003, respectively. The table below summarizes the financial information for ERGSS:

	2005		2004		2003
	(In thousands)
Operating revenues	$	6,448	$	6,752	$	6,514
Operating income	$	3,947	$	4,308	$	4,141
Equity income	$	3,245	$	3,511	$	3,208
The Company’s share of equity income	$	1,623	$	1,755	$	1,604
Current assets	$	6,203	$	4,232	$	4,358
Non-current assets		20,736		22,086		20,564
Total assets	$	26,939	$	26,318	$	24,922
Current liabilities	$	13,198	$	6,242	$	5,636
Non-current liabilities		—		7,313		9,013
Equity		13,741		12,763		10,273
Total liabilities and equity	$	26,939	$	26,318	$	24,922
The Company’s equity investment in ERGSS	$	6,870	$	6,381	$	5,137

      At December 31, 2004, the Company’s had common equity investments of $1.2 million in two capital trust subsidiaries. In 2005, these investments were redeemed by the trusts. Refer to Note 4 for further information.

Note 13. Commitments and Contingencies

     Capital Investments. The Company’s plans for expansion and improvement of its business properties are continually reviewed. Aggregate capital expenditures for property in 2006 are projected to be approximately $42.1 million. The Company may also, as part of the execution of its strategic plan, make acquisitions of, or investments in, other businesses.

     Lease Commitments. The Company leases buildings, vehicles and equipment. The resulting leases are classified as operating leases in accordance with SFAS 13, “Accounting for Leases.” A significant portion of the Company’s vehicles are leased. Leases on the majority of the Company’s new vehicles are for a minimum of twelve months. The Company has the right to extend each vehicle lease annually and to cancel the extended lease at any time. During 2002, the Company sold two of its buildings located in Port Huron, Michigan to Acheson Ventures LLC (“Acheson”) and leased these facilities back over the period January 2003 through January 2005. The annual lease payments associated with these facilities amounted to approximately $0.5 million. In February 2005, the Company began leasing its new Port Huron headquarters building from Acheson for annual lease payments of $0.8 million.

      The Company’s future minimum lease payments that have initial or remaining noncancelable lease terms in excess of one year at December 31, 2005, totaled $15.2 million consisting of (in millions):

2006	$	1.9
2007	$	1.8
2008	$	1.9
2009	$	1.9
2010	$	1.9
Thereafter	$	5.8

88

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Note 13. Commitments and Contingencies (continued)

      Total lease payments were approximately $2.8 million, $2.9 million and $2.7 million in 2005, 2004 and 2003, respectively. The annual future minimum lease payments are less than the lease payments incurred in 2003 through 2005, because most of the vehicle leases at December 31, 2005, were on amonth-to-month basis and were subject to cancellation at any time. However, management expects to renew or replace substantially all of these leases.

     Sublease Commitments.In February 2005, in conjunction with the commencement of the Company’s lease of its new Port Huron headquarters building from Acheson, Acheson began paying the lease payments on the Farmington Hills, Michigan office space that was the Company’s former headquarters. Acheson’s obligation to make these lease payments extends through March 31, 2011, when the Company’s lease on the Farmington Hills office space expires. As of December 31, 2005, the future payments that Acheson is obligated to pay amounted to approximately $2.4 million. For additional information on Acheson’s obligation and related legal action, refer to the caption “Other Contingencies” within this Note 13.

     Commitments for Natural Gas Supplies. The Company enters into contracts to purchase natural gas and natural gas transportation and storage services from various suppliers for its Gas Distribution Business. These contracts, which have expiration dates that range from 2004 to 2010, are used to assure an adequate supply of natural gas to meet the needs of customers and to minimize exposure to market price fluctuations. The Company’s gas purchase contractual obligations as of December 31, 2005, total $228.9 million, consisting of (in millions):

2006	$	168.7
2007	$	26.6
2008	$	19.4
2009	$	11.6
2010	$	2.6
Thereafter	$	—

     Guarantees. The Company has issued letters of credit through financial institutions for the benefit of third parties that have extended credit to the Company. At December 31, 2005, the outstanding letters of credit amounted to $16.8 million. Under the terms of these letters of credit, if the Company does not pay amounts when due under the covered contracts, the beneficiary may present its claim for payment to the financial institution, which will in return request payment from the Company. The letters of credit are entered into on a short term basis, normally everysix-to-twelve months, and are then renewed for another short term period. At December 31, 2005, the scheduled expiration dates for these letters of credits ranged from January 2006 through September 2006.

     Environmental Issues. Prior to the construction of major interstate natural gas pipelines, gas for heating and other uses was manufactured from processes involving coal, coke or oil. Residual byproducts of these processes may have caused environmental conditions that require investigation and remediation. The Company owns seven sites in Michigan where such manufactured gas plants were located. Even though the Company never operated manufactured gas facilities at four of the sites, and did so at another site for only a brief period of time, the Company is subject to local, state and federal laws and regulations that require, among other things, the investigation and, if necessary, the remediation of contamination associated with these sites, irrespective of fault, legality of initial activity, or ownership, and which may impose liability for damage to natural resources. The Company has complied with the applicable Michigan Department of Environmental Quality (“MDEQ”) requirements, which require current landowners to mitigate unacceptable risks to human health from the byproducts of manufactured gas plant operations and to notify the MDEQ and adjacent property owners of potential contaminant migration. The Company is currently investigating these sites and anticipates conducting any necessary additional investigatory and remedial activities as appropriate. The

89

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Note 13. Commitments and Contingencies (continued)

Company has already remediated and closed a site related to one of the manufactured gas plant sites, with the MDEQ’s approval.

      The Company is also attempting to identify other potentially responsible parties to bear some or all of the costs and liabilities associated with the investigatory and remedial activities at several of these sites and also is pursuing recovery of the costs of these activities from insurance carriers. The Company is unable to predict, however, whether and to what extent it will be successful in involving other potentially responsible parties in investigatory or remedial activities, or in bearing some or all of the costs thereof, or in securing insurance recoveries for some or all of the costs associated with these sites.

      The Company also is unable to estimate, at present, the costs that may be incurred in connection with the investigation and remediation of these sites or other potential environmental liabilities relating to these sites. In accordance with an MPSC accounting order, environmental assessment and remediation costs associated with certain manufactured gas plant sites are deferred and amortized over ten years. Rate recognition of the related amortization expense does not begin until a review of the related costs in a base rate case.

     Personal Property Taxes. The Company and other Michigan utilities have asserted that Michigan’s valuation tables in effect prior to 2000 resulted in the substantial overvaluation of utility personal property. Valuation tables established by the Michigan State Tax Commission (“STC”) are used to estimate the reduction in value of personal property based on the property’s age. In 1998, the Company began filing its personal property tax information with local taxing jurisdictions, using a revised calculation of the value of personal property subject to taxation. A number of local taxing jurisdictions accepted the revised calculation, and the Company recorded lower property tax expense in 1998 and subsequent years associated with these taxing jurisdictions. The Company has also filed appeals to recover excess payments made in 1997 and subsequent years based on the revised calculation and recorded lower property tax expense as a result of the filings.

      In November 1999, the STC approved new valuation tables for utility personal property. The new tables became effective in 2000 and are being used for current year assessments in most jurisdictions. However, several local taxing jurisdictions took legal actions attempting to prevent the STC from implementing the new valuation tables and others continued to prepare assessments based on the superseded tables. The legality of the new valuation tables providing lower values for gas distribution property was resolved in favor of the STC in January 2004.

      Throughout the period that the prior years property tax appeals have been outstanding, the Company has reflected the amount of the excess property tax payments that it expected to recover in prepaid expenses in its Consolidated Statements of Financial Position. During 2004, the Company reduced its estimate for recovery of certain of these prior years excess property tax payments by $1.4 million, such that at December 31, 2004, the Company had approximately $2.5 million recorded in prepaid expenses for its estimated recovery. During 2005, the Company initiated settlement offers to all taxing jurisdictions involved with the property tax appeals. Numerous taxing jurisdictions have accepted the Company’s settlement offer and, as a result, the Company reduced its 2005 property tax expense by approximately $0.5 million. As of December 31, 2005, the Company had received cash refunds of $0.5 million and had approximately $2.4 million recorded in prepaid expenses in its Consolidated Statements of Financial Position representing prior years excess property tax payments expected to be recovered. The Company will continue to seek settlements with taxing jurisdictions that have not yet accepted the Company’s offers. If any taxing jurisdictions do not accept the Company’s settlement offers, the property tax appeals involving these jurisdictions would move forward before the Michigan Tax Tribunal.

     Other Contingencies. In the normal course of business, the Company may be a party to lawsuits and administrative proceedings before various courts and government agencies. The Company also may be involved in private dispute resolution proceedings. These lawsuits and proceedings may involve personal injury,

90

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Note 13. Commitments and Contingencies (continued)

property damage, contractual issues and other matters (including alleged violations of federal, state and local laws, rules, regulations and orders). Management cannot predict the outcome or timing of any pending or threatened litigation or of actual or possible claims. Except as otherwise stated, management believes resulting liabilities, if any, will not have a material adverse impact upon the Company’s financial position, results of operations, or cash flows.

      In October 2004, two Company subsidiaries (SEMCO Energy Services, Inc. and SEMCO Pipeline Company) were added as defendants in a putative class action lawsuit brought in federal district court in West Virginia alleging that the approximately 30 defendants named in the lawsuit engaged in gas marketing activities that violated state and federal anti-trust laws and otherwise tortiously interfered with the business opportunities of the plaintiffs from 1996 to present. On October 4, 2005, the court granted a motion to dismiss filed by certain defendants, including the Company’s subsidiaries, as to federal anti-trust claims arising prior to October 25, 2000. On January 30, 2006, the court declined a request that it amend its dismissal order to include any state anti-trust claims arising during the same period. The Company plans to file additional motions raising defenses with respect to all remaining claims. The Company sold its gas marketing business in 1999.

      In connection with the issuance of CPS and Warrants to K-1, during 2004, the Company agreed to seek certain rulings from the RCA. As part of RCA proceedings instituted with respect to the rulings sought by the Company, the Alaska Attorney General asserted, among other things, that (i) the Company’s issuance of the CPS and Warrants to K-1 resulted in a control change requiring prior approval by the RCA, (ii) such a control change did not adversely affect ENSTAR and therefore should be approved by the RCA, and (iii), in connection with approving this control change, the RCA should institute a rate proceeding to review the base rates of ENSTAR, using a 2005 test year and a new depreciation study for ENSTAR’s property. The Company believed that no control change occurred upon the issuance of the CPS and Warrants to K-1 and thus no RCA approval was required. The Company also opposed the proposal that the RCA institute a rate proceeding to review ENSTAR’s base rates and, in connection with that review, order that a depreciation study of ENSTAR’s property be done.

      After repurchasing the CPS and Warrants from K-1 on March 15, 2005, the Company filed a motion to terminate proceedings with the RCA on the basis that the repurchase made such proceedings moot. The Company also continued to oppose the proposal that the RCA institute a rate proceeding to review ENSTAR’s base rates and conduct a depreciation study. On June 20, 2005, the RCA terminated the proceeding. It also required ENSTAR to file a revenue requirement and cost of service study (including rate design data) with the RCA by June 6, 2008 (using a test year ended December 31, 2007). In addition, ENSTAR is required to file a depreciation study of utility plant (as of December 31, 2006) by June 1, 2007. These filings also will include the Company’s APC subsidiary.

      In September 2002, the Company agreed to relocate its headquarters to Port Huron, Michigan, and leased part of a new office building in Port Huron from Acheson. As part of the transaction, Acheson agreed to sublease office space occupied by the Company in Farmington Hills, Michigan, and, beginning in February 2005, began to pay the Company’s Farmington Hills lease costs (approximately $36,000/ month until March 31, 2011, when the Farmington Hills lease expires), as agreed. In June 2005, Acheson ceased making these payments, ostensibly because the Company had breached its obligations by maintaining a satellite office in Troy, Michigan, for certain executives who also have offices in the Company’s Port Huron headquarters. The Company has filed an action in Michigan state court, seeking (i) damages for Acheson’s failure to pay the Company’s Farmington Hills lease costs, and (ii) a declaratory judgment that the Company has met its obligations to Acheson. To mitigate its damages, the Company is paying the Farmington Hills lease costs and is attempting to market the space to prospective subtenants. On January 16, 2006, Acheson answered the Company’s complaint, filed counter-claims alleging breach of contract, fraud, and negligent misrepresentation, and sought a change of venue for these proceedings, to Port Huron, Michigan. The Company has made filings to answer Acheson’s counter claims, denying any liability to Acheson, and opposing a change of venue.

91

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Note 14. Acquisitions, Disposals and Discontinuation of Operations

     Acquisition of Peninsular Gas Company. On June 1, 2005, the Company acquired substantially all of the assets and certain liabilities of Peninsular Gas for $3.0 million in cash. The assets acquired included approximately $0.3 million in cash. In accordance with the asset purchase agreement, the Company paid an additional $0.3 million to the seller for excess working capital acquired. The cash paid by the Company to acquire Peninsular Gas, including $0.1 million of transaction costs and the excess working capital payment, amounted to $3.1 million, net of the cash acquired. This acquisition adds approximately 4,000 customers to the Company’s Gas Distribution Business in the upper peninsula of Michigan. The operating results of Peninsular Gas for the period June 1 through December 31, 2005, are reflected in the Company’s Consolidated Statements of Operations for 2005. The acquired assets and assumed liabilities are reflected in the Company’s Consolidated Statements of Financial Position at December 31, 2005.

     Disposal of Construction Services Business Segment. The Company began marketing the construction services business for sale during the first quarter of 2004. As a result, the Company has accounted for the business as a discontinued operation and, accordingly, the operating results and the estimated loss on the disposal of this business are segregated and reported as discontinued operations in the Consolidated Statements of Operations. In September 2004, the Company sold the assets of its construction services business to InfraSource Services, Inc. for approximately $21.3 million. The proceeds from the sale were used for capital expenditures and general corporate purposes.

      Operating income (losses), net of income taxes, from the discontinued operations were $0.5 million, $(4.6) million and $(24.9) million, respectively, for the 2005, 2004 and 2003. The Company’s income from discontinued operations for 2005 was from a settlement of litigation. Also included in discontinued operations for 2004 is a loss of $4.7 million, net of income taxes, that the Company incurred on the disposal of the discontinued segment.

      Components of amounts reflected in the Consolidated Statements of Operations for the construction services business are presented in the following table:

	Year Ended December 31,
	2005			2004			2003
	(In thousands)
Revenues	$	—		$	34,106		$	72,400
Operating expenses		(850	)		39,722			82,894
Goodwill impairment charge		—			—			17,649
Asset impairment charge		—			—			2,825
Operating income (loss)		850			(5,616	)		(30,968	)
Other deductions		—			(807	)		(1,265	)
Income tax (expense) benefit		(312	)		1,782			7,362
Income (loss) from discontinued operations	$	538		$	(4,641	)	$	(24,871	)
Loss on divestiture of construction services operations, net of income tax (expense) benefit of $0, $1,722 and $0	$	—		$	(4,698	)	$	—

92

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Note 15. Quarterly Financial Information (Unaudited)

      In the opinion of the Company, the following quarterly information includes all adjustments necessary for a fair statement of the results of operations for such periods. Earnings per share for each quarter is calculated based upon the weighted average number of shares outstanding during each quarter. As a result, adding the earnings per share for each quarter of a year may not equal annual earnings per share due to changes in shares outstanding throughout the year. Due to the seasonal nature of the Company’s Gas Distribution Business, the results of operations reported on a quarterly basis show substantial variations.

		Quarters during 2005
		First		Second			Third			Fourth
		(In thousands, except per share amounts)
Operating revenues		$	226,560	$	95,633		$	62,310		$	230,599
Operating income (loss)			30,143		7,143			(1,734	)		23,952
Income (loss) from continuing operations			12,496		(2,113	)		(7,930	)		9,284
Discontinued operations			—		—			538			—
Net income (loss) available to common shareholders			3,232		(3,058	)		(8,339	)		8,334
Earnings per share from income (loss) from continuing operations:
	— basic		0.11		(0.11	)		(0.29	)		0.25
	— diluted		0.11		(0.11	)		(0.29	)		0.22
Earnings per share from net income (loss) available to common shareholders:
	— basic		0.11		(0.11	)		(0.27	)		0.25
	— diluted		0.11		(0.11	)		(0.27	)		0.22
Dividends paid per share			—		—			—			—
Dividends declared per share			—		—			—			—

		Quarters during 2004
		First			Second			Third			Fourth
		(In thousands, except per share amounts)
Operating revenues		$	207,784		$	81,762		$	54,034		$	164,756
Operating income (loss)			31,290			4,934			(1,492	)		10,753
Income (loss) from continuing operations			12,861			(3,544	)		(7,335	)		2,174
Discontinued operations			(4,776	)		(2,344	)		(1,129	)		(1,090	)
Net income (loss) available to common shareholders			8,023			(6,756	)		(9,617	)		(36	)
Earnings per share from income (loss) from continuing operations:
	— basic		0.46			(0.16	)		(0.30	)		0.04
	— diluted		0.45			(0.16	)		(0.30	)		0.04
Earnings per share from net income (loss) available to common shareholders:
	— basic		0.29			(0.24	)		(0.34	)		(0.00	)
	— diluted		0.28			(0.24	)		(0.34	)		(0.00	)
Dividends paid per share			0.075			0.075			—			—
Dividends declared per share			—			0.075			—			—

93

SCHEDULE II CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS

			Additions for		Deductions From
			Provisions		Reserves for
	Balance		Charged or		Purpose for		Balance
	Beginning		(Credited)		Which the Reserve		End of
Description	of Period		to Income		was Provided		Period
	(In thousands)
Year Ended December 31, 2005
Allowance for doubtful accounts deducted from receivables in the Statement of Financial Position	$	2,247	$	2,378	$	2,867	$	1,758
Year Ended December 31, 2004
Allowance for doubtful accounts deducted from receivables in the Statement of Financial Position	$	2,387	$	3,133	$	3,273	$	2,247
Reserve for restructuring costs included in current liabilities and deferred credits in the Statement of Financial Position	$	278	$	—	$	278	$	—
Year Ended December 31, 2003
Allowance for doubtful accounts deducted from receivables in the Statement of Financial Position	$	1,909	$	3,616	$	3,138	$	2,387
Reserve for restructuring costs included in current liabilities and deferred credits in the Statement of Financial Position	$	1,093	$	—	$	815	$	278

94

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

      None.

Item 9A. Controls and Procedures

     Disclosure Controls and Procedures. As of the end of the period covered by this report, the Company carried out an evaluation, under the supervision and with the participation of management, including the Chief Executive Officer (“CEO”) and the Chief Financial Officer (“CFO”), of the effectiveness of the design and operation of the Company’s disclosure controls and procedures as defined in Rules 13a-15(e) and15d-15(e) of the Securities and Exchange Act of 1934. Based on that evaluation, the CEO and the CFO have concluded that the Company’s disclosure controls and procedures were effective as of December 31, 2005. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that the Company’s disclosure controls and procedures will detect or uncover every situation involving the failure of persons within the Company to disclose material information otherwise required to be set forth in the Company’s periodic reports.

     Management’s Report on Internal Control Over Financial Reporting. Management is responsible for establishing and maintaining adequate internal control over financial reporting (as such term is defined in Exchange Act Rule 13a-15(f)). The Company’s internal control over financial reporting is a process designed under the supervision the Company’s CEO and CFO to provide reasonable assurance regarding the reliability of financial reporting and the preparation of the Company’s financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America. The Company’s internal control over financial reporting include those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the Company’s assets; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that the Company’s receipts and expenditures are being made only in accordance with authorizations of management and the Company’s Board; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the Company’s assets that could have a material effect on the financial statements.

      Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

      Management assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2005. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control-Integrated Framework. Based on this assessment, management concluded that, as of December 31, 2005, the Company’s internal control over financial reporting was effective.

      Management’s assessment of the effectiveness of the Company’s internal control over financial reporting as of December 31, 2005 has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in its report contained in Item 8 of this Form 10-K.

     Changes in Internal Control Over Financial Reporting. During the fourth quarter of the year ended December 31, 2005, no change in the Company’s internal control over financial reporting (as such term is defined in Rules 13a-15(f) and15d-15(f) of the Securities and Exchange Act of 1934) occurred that has materially affected or is reasonably likely to materially affect, the Company’s internal control over financial reporting.

95

Item 9B. Other Information

Item 1.01 Entry into a Material Definitive Agreement.

      During 2004, the Company hired new executive officers with substantial utility industry experience. The compensation of these and other executive officers is based on the compensation paid to executives at a peer group of utilities, with an overall objective of providing competitive compensation at or near the 50th percentile of the peer group data. Refer to Item 11 of this Form 10-K for additional information.

      On March 10, 2006, with Board authorization, the Compensation Committee of the Board (the “Committee”) approved the annual base salaries for the Company’s CEO and its four most highly compensated executive officers for the Company’s last completed fiscal year (the “named executive officers”). The Committee also approved cash bonus awards under the Company’s Short-Term Incentive Plan (“STIP”) for certain executive officers, including all of the named executive officers, for the fiscal year ended December 31, 2005. Finally, the Committee established the performance criteria to be used in establishing cash bonus awards and award grants for the fiscal year ending December 31, 2006 under the STIP and the Company’s 2004 Stock Award and Incentive Plan (referred to here as the “LTIP” and elsewhere as the “2004 Plan”).

Base Salaries of Named Executive Officers

      On March 10, 2006, with Board authorization, the Committee approved new annual base salaries (effective as of July 1, 2006) for the named executive officers. The following table (which is also included as Exhibit 10.21 to this Form 10-K) sets forth the new annual base salary levels of the named executive officers:

		Base Salary
		Effective
Name and Position		July 2006
George A. Schreiber, Jr.		$	535,000
	President and CEO
Michael V. Palmeri		$	285,000
	Senior Vice President, Treasurer and CFO
Eugene N. Dubay		$	275,000
	Senior Vice President of Operations
Peter F. Clark		$	255,000
	Senior Vice President and General Counsel
Mark T. Prendeville		$	180,000
	Vice President and Deputy General Counsel

Cash Bonus Awards under the STIP for 2005

      On March 10, 2006, with Board authorization, the Committee approved the following cash bonus awards for the named executive officers under the STIP for the fiscal year ended December 31, 2005:

		Cash Bonus
		Award under
Name and Position		STIP for 2005
George A. Schreiber, Jr.		$	200,000
	President and CEO
Michael V. Palmeri		$	83,200
	Senior Vice President, Treasurer and CFO
Eugene N. Dubay		$	72,800
	Senior Vice President of Operations
Peter F. Clark		$	65,800
	Senior Vice President and General Counsel
Mark T. Prendeville		$	40,765
	Vice President and Deputy General Counsel

96

2006 Performance Criteria under the STIP

      Whether a participant obtains his or her target award under the STIP depends on achievement of certain corporate financial results and then is further weighted based on the individual’s annual performance assessment ranking. Individual performance weighting varies based on employment level, as described in the STIP. For 2006, the specific STIP corporate financial results that will be measured are net income and net operating profit after tax, each of these measures weighted equally when determining whether the corporate financial results were met.

      In addition, with Board authorization, the Committee approved the following target bonuses for each of the named executive officers in the following table (a copy of which is filed as Exhibit 10.18.1 to this Form 10-K), which may be decreased depending on each named executive officer’s performance and the corporate financial results of the Company, as permitted under the STIP:

		Target Bonus That May
		be Granted Under STIP
Name and Position		for 2006
George A. Schreiber, Jr.			60% of Base Salary
	President and CEO
Michael V. Palmeri			40% of Base Salary
	Senior Vice President, Treasurer and CFO
Eugene N. Dubay			50% of Base Salary
	Senior Vice President of Operations
Peter F. Clark			35% of Base Salary
	Senior Vice President and General Counsel
Mark T. Prendeville			30% of Base Salary
	Vice President and Deputy General Counsel

      This explanation of the performance criteria under the STIP is qualified in its entirety by reference to the full text of the STIP, a copy of which is filed as an exhibit to the Company’s Form 10-K for the fiscal year ended December 31, 2004, filed March 8, 2005.

2006 Performance Criteria under the LTIP

      Whether a participant will obtain a target award for 2006 under the LTIP depends on (i) the growth of earnings per share compared to a peer group of gas utility companies, and (ii) achieving a certain target return on invested capital. These two factors are measured over a cumulative three-year period so that these LTIP performance measures for 2006 will be evaluated as of December 31, 2008. In addition, these two factors are weighted equally in determining the LTIP award.

      This explanation of the performance criteria under the LTIP is qualified in its entirety by reference to the full text of (i) the LTIP, a copy of which is filed as Appendix A to the Company’s 2004 Proxy Statement, filed April 6, 2004; (ii) the Form of Employee Performance Share Unit Award Agreement, a copy of which is filed as an exhibit to the Company’s Form 10-K for the fiscal year ended December 31, 2004, filed March 8, 2005; (iii) the Forms of Restricted Stock Award Agreements (for the chairmen, for the directors and for employees), copies of which are filed as exhibits to the Company’s Form 8-K filed July 1, 2005; and (iv) the Form of Restricted Stock Unit Award Agreement, a copy of which is filed as an exhibit to the Company’s Form 8-K filed July 1, 2005.

PART III

Item 10. Directors and Executive Officers of the Registrant

      The information appearing under the captions “Information About Nominees, Directors and Executive Officers,” the subheading “Audit Committee” under the caption “Committees of the Board of Directors and Meeting Attendance” and “Section 16(a) Beneficial Ownership Reporting Compliance” in the Company’s

97

definitive Proxy Statement (to be filed pursuant to Regulation 14A) with respect to the Company’s 2006 Annual Meeting of Common Shareholders is incorporated by reference herein. In February 2003, the Company’s Board adopted a Code of Business Conduct and Ethics (“Code of Ethics”) that applies to all of the Company’s employees (including the Company’s officers), directors, affiliates, agents, consultants, advisors and representatives. The Company had a Code of Ethics in place prior to February 2003, but expanded the information provided into a handbook on conduct and ethics that would be better understood by those required to abide by it. The Company’s Code of Ethics was filed as Exhibit No. 99.2 to the Form 10-K for the year ended December 31, 2003, and can also be found on the Company’s website at www.semcoenergy.com in the Investor Information section under Corporate Governance.

Item 11. Executive Compensation

      The information appearing under the captions “Compensation of Executive Officers and Directors” (including the subheadings “Summary Compensation Table,” “Option Grants in 2005,” “Aggregated Option Exercises in 2005 and Option Values at December 31, 2005,” “Executive Severance Agreements,” “Employee Pension Plan,” “Pension Plan Table,” “Total Pension Benefits,” “Combined Pension Plan and Supplemental Retirement Plan Table,” “Supplemental Executive Retirement Plan” and “Director Compensation”), “Compensation Committee Report on Executive Compensation” and “Performance Graph” in the Company’s definitive Proxy Statement (to be filed pursuant to Regulation 14A) with respect to the Company’s 2006 Annual Meeting of Common Shareholders is incorporated by reference herein. There are no compensation committee interlocks or insider participation.

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

      The information appearing under the caption “Beneficial Ownership” in the Company’s definitive Proxy Statement (to be filed pursuant to Regulation 14A) with respect to the Company’s 2006 Annual Meeting of Common Shareholders is incorporated by reference herein. Information regarding the Company’s equity compensation plans, including plans approved by security holders and plans not approved by security holders, appearing under the caption “Equity Compensation Plan Information” in the Company’s definitive Proxy Statement (to filed pursuant to Regulation 14A) with respect to the Company’s 2006 Annual Meeting of Common Shareholders is incorporated by reference herein.

Item 13. Certain Relationships and Related Transactions

      The information appearing under the caption “Certain Relationships and Related Transactions” in the Company’s definitive Proxy Statement (to be filed pursuant to Regulation 14A) with respect to the Company’s 2006 Annual Meeting of Common Shareholders is incorporated by reference herein.

Item 14. Principal Accountant Fees and Services

      The information appearing under the caption “Principal Accountant Fees” in the Company’s definitive Proxy Statement (to be filed pursuant to Regulation 14A) with respect to the Company’s 2006 Annual Meeting of Common Shareholders is incorporated by reference herein.

98

PART IV

Item 15. Exhibits, Financial Statement Schedules

(a)	1	Financial statements filed as part of this report are listed in Item 8 of this Form 10-K, and reference is made thereto.
(a)	2	Financial statement schedules filed as part of this report are listed in Item 8 of this Form 10-K, and reference is made hereto.
(a)	3	Exhibits, including those incorporated by reference, are included in the list of exhibits below.
(b)		The exhibits filed herewith are identified in Item 15(a)3 above.
(c)		The financial statement schedules filed herewith are identified under Item 15(a)2 above.

99

EXHIBITS, INCLUDING THOSE INCORPORATED BY REFERENCE

				Filed
Exhibit						By
No.			Description	Herewith		Reference
	3	.1	Articles of Incorporation of SEMCO Energy, Inc., as restated June 25, 1999, and amendments thereto through May 28, 2004, including Certificate of Designation of 6% Series B Convertible Preference Stock filed March 19, 2004.(m)				x
	3	.1.1	Certificate of Designation of 5% Series B Convertible Cumulative Preferred Stock, filed March 14, 2005.(q)				x
	3	.2	Bylaws — last revised June 28, 2005.(s)				x
	4	.1	Rights Agreement dated as of April 15, 1997 with Continental Stock Transfer & Trust Company, as Rights Agent.(b)				x
	4	.1.2	Amended Rights Agreement as of March 19, 2004 with National City Bank (successor Rights Agent).(l)				x
	4	.2	Indenture relating to Senior Debt Securities dated as of October 23, 1998, with Bank One Trust Company (formerly NBD Bank) as Trustee.(r)				x
	4	.2.1	Third Supplemental Indenture relating to Senior Debt Securities dated as of June 15, 2001, with Bank One Trust Company as Trustee.(e)				x
	4	.2.2	Fourth Supplemental Indenture relating to Senior Debt Securities dated as of September 19, 2002, with Bank One Trust Company as Trustee.(h)				x
	4	.3	Indenture, dated as of May 15, 2003, between SEMCO Energy, Inc. and Fifth Third Bank, relating to SEMCO Energy, Inc.’s 73/4% Senior Notes due 2013.(i)				x
	4	.4	Indenture, dated as of May 21, 2003, between SEMCO Energy, Inc. and Fifth Third Bank, relating to SEMCO Energy, Inc.’s 71/8% Senior Notes due 2008.(i)				x
	4	.5	Registration Rights Agreement, dated March 15, 2005, for the benefit of holders of 5% Series B Convertible Cumulative Preferred Stock.(q)				x
	10	.1	1997 Long-Term Incentive Plan.(a)				x
	10	.2	Amendment (dated August 10, 2001) to Employment Agreement with William L. Johnson.(f)				x
	10	.3	Executive Security Agreement.(c)				x
	10	.4	Split-Dollar Agreement, dated April 14, 2000.(c)				x
	10	.5	Executive Security Trust, dated April 14, 2000.(c)				x
	10	.6	Stock Option Plan of 2000, dated April 14, 2000.(d)				x
	10	.7	Deferred Compensation and Stock Purchase Plan for Non-Employee Directors, effective as of January 1, 2002.(g)				x
	10	.7.1	First Amendment to the Deferred Compensation and Stock Purchase Plan for Non-Employee Directors, effective as of January 1, 2005.(v)				x
	10	.8	First Amended and Restated Deferred Compensation and Stock Purchase Plan for Non-Employee Directors amended and restated January 1, 2006.		x
	10	.9	2004 Stock Award and Incentive Plan.(j)				x
	10	.9.1	Form of Employee Stock Option Agreement for stock options granted pursuant to the 2004 Stock Award and Incentive Plan.(p)				x
	10	.9.2	Form of Employee Performance Share Unit Award Agreement for performance share units granted pursuant to the 2004 Stock Award and Incentive Plan.(p)				x
	10	.9.3	Form of Restricted Stock Grant Agreement For Directors.(s)				x
	10	.9.4	Form of Restricted Stock Grant Agreement For Chairmen.(s)				x

100

				Filed
Exhibit						By
No.			Description	Herewith		Reference
	10	.9.5	Form of Restricted Stock Unit Award Agreement.(s)				x
	10	.9.6	Form of Stock Option Agreement pursuant to executive agreements.(s)				x
	10	.10	Severance Agreement dated June 29, 2005 between SEMCO Energy, Inc. and George A. Schreiber, Jr.(s)				x
	10	.10.1	Corrected exhibits D and E to Severance Agreement between SEMCO Energy, Inc. and George A. Schreiber, Jr. dated June 29, 2005.(t)				x
	10	.11	Severance Agreement dated June 29, 2005 between SEMCO Energy, Inc. and Peter F. Clark.(s)				x
	10	.12	Severance Agreement dated June 29, 2005 between SEMCO Energy, Inc. and Eugene N. Dubay.(s)				x
	10	.13	Severance Agreement dated June 29, 2005 between SEMCO Energy, Inc. and Michael V. Palmeri.(s)				x
	10	.14	Severance Agreement dated June 29, 2005 between SEMCO Energy, Inc. and Lance S. Smotherman.(s)				x
	10	.15	Change in Control Severance Agreement between SEMCO Energy, Inc. and Mark T. Prendeville dated June 29, 2005.(s)				x
	10	.16	Employment Agreement dated July 8, 2004 between SEMCO Energy, Inc. and Doris Friedrich Galvin.(n)				x
	10	.17	Severance and Consulting Agreement between SEMCO Energy, Inc. and Doris F. Galvin effective February 17, 2005.(o)				x
	10	.18	Short Term Incentive Plan effective January 1, 2005.(p)				x
	10	.18.1	2006 Target Bonuses under the Company’s Short-Term Incentive Plan.		x
	10	.19	2004 Supplemental Executive Retirement Plan.(p)				x
	10	.20	Non-Employee Director Compensation Summary.(s)				x
	10	.21	Base Salaries for Named Executive Officers.		x
	10	.22	Second Amended and Restated Credit Agreement, dated as of September 15, 2005 by and among SEMCO Energy, Inc. as the Company, the various financial institutions as party thereto, as lenders, and LaSalle Bank Midwest National Association, a national banking association, as Administrative Agent, National City Bank of the Midwest, a national banking association, as Syndication Agent, U.S. Bank, N.A., as Documentation Agent and LaSalle Bank Midwest National Association, a national banking association, as Arranger (the “Second Amended and Restated Credit Agreement”).(u)				x
	10	.22.1	First Amendment to Second Amended and Restated Credit Agreement, dated February 10, 2006.		x
	10	.22.2	Letter Agreement between SEMCO Energy, Inc. and LaSalle Bank Midwest National Association, as Swing Line Lender under the Second Amended and Restated Credit Agreement, dated February 15, 2006.		x
	10	.23	Gas Sales Agreement between Marathon Oil Company and Alaska Pipeline Company dated as of May 1, 1988.(v)				x
	10	.23.1	First Amendment, dated as of December 20, 1989, to Gas Purchase Agreement Between Marathon Oil Company and Alaska Pipeline Company dated May 1, 1988.(v)				x
	10	.23.2	Second Amendment, dated as of November 19, 1991, to Gas Purchase Agreement Between Marathon Oil Company and Alaska Pipeline Company dated May 1, 1988.(v)				x

101

				Filed
Exhibit						By
No.			Description	Herewith		Reference
	10	.24	Gas Sales Agreement between Union Oil Company of California and Alaska Pipeline Company effective November 17, 2000.		x
	10	.24.1	Addendum No. 1, effective as of November 15, 2001, to Gas Sales Agreement between Union Oil Company of California and Alaska Pipeline Company.		x
	10	.25	Gas Sales Agreement between Anadarko Petroleum Corporation, Phillips Alaska, Inc. and Alaska Pipeline Company effective January 1, 2002.		x
	10	.26	Assignment Approval (dated as of December 26, 2002) by Alaska Pipeline Company and Joinder and Ratification by Aurora Gas, LLC of the Gas Sales Agreement between Anadarko Petroleum Corporation, Phillips Alaska, Inc. and Alaska Pipeline Company effective January 1, 2002.		x
	10	.27	Assignment Approval (dated as of January 13, 2003) by Alaska Pipeline Company and Joinder and Ratification by Aurora Gas, LLC of the Gas Sales Agreement between Anadarko Petroleum Corporation, Phillips Alaska, Inc. and Alaska Pipeline Company effective January 1, 2002.		x
	10	.28	Gas Purchase Contract between Shell Oil Company and Alaska Pipeline Company dated as of December 20, 1982.		x
	10	.28.1	Letter Agreement No. 1 dated May 24, 1983 amending the Gas Purchase Contract between Shell Oil Company and Alaska Pipeline Company dated as of December 20, 1982.		x
	10	.28.2	Letter Agreement between Shell Western E&P Inc. and Alaska Pipeline Company dated January 26, 1988 amending the Gas Purchase Contract between Shell Oil Company and Alaska Pipeline Company dated as of December 20, 1982.		x
	10	.29	Partial Assignment of the Gas Purchase Contract between Shell Oil Company and Alaska Pipeline Company dated as of December 20, 1982, as amended, from Shell Western E&P Inc. to ARCO Alaska, Inc. effective October 1, 1989.		x
	10	.30	Agreement between Alaska Pipeline Company and Shell Western E&P Inc. dated November 15, 1991, to amend a retained interest in the Gas Purchase Contract between Shell Oil Company and Alaska Pipeline Company dated as of December 20, 1982, as amended.		x
	10	.31	Agreement between Alaska Pipeline Company and ARCO Alaska, Inc. dated November 15, 1991, to amend an assigned interest in the Gas Purchase Contract between Shell Oil Company and Alaska Pipeline Company dated as of December 20, 1982, as amended.		x
	10	.32	Partial Assignment of Gas Purchase Contract between Shell Oil Company and Alaska Pipeline Company dated as of December 20, 1982, as amended, from Shell Western E&P Inc. to Chevron U.S.A. Inc. effective January 1, 1993.		x
	10	.33	Assignment and Conveyance of the retained interest in the Gas Purchase Contract between Shell Oil Company and Alaska Pipeline Company dated as of December 20, 1982, as amended, from Shell Western E&P Inc. to the Municipality of Anchorage d/b/a Municipal Light & Power effective September 1, 1996.		x
	10	.34	Partial Assignment of Gas Purchase Contract between Shell Oil Company and Alaska Pipeline Company dated as of December 20, 1982, as amended, from ARCO Alaska, Inc. to CH-Twenty, Inc. effective December 27, 1996.		x

102

				Filed
Exhibit						By
No.			Description	Herewith		Reference
	10	.35	Partial Assignment of Gas Purchase Contract between Shell Oil Company and Alaska Pipeline Company dated as of December 20, 1982, as amended, from CH-Twenty, Inc. to ARCO Beluga, Inc. effective January 7, 1997.		x
	12	.1	Ratio of Earnings to Fixed Charges.		x
	12	.2	Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividends.		x
	14		Code of Business Conduct and Ethics approved February 20, 2003.(k)				x
	21		Subsidiaries of the Registrant.		x
	23		Consent of Independent Registered Public Accounting Firm.		x
	31	.1	CEO Certification as adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.		x
	31	.2	CFO Certification as adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.		x
	32	.1	CEO and CFO Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.		x
	99	.1	Proxy Statement with respect to SEMCO Energy, Inc.’s 2006 Annual Meeting of Common Shareholders.(w)				x

Key to Exhibits Incorporated by Reference

(a)	Filed with SEMCO Energy, Inc.’s 1997 Proxy Statement, filed March 6, 1997, File No. 0-8503.
(b)	Filed with SEMCO Energy, Inc.’s Form 10-K for the fiscal year ended December 31, 1996, filed March 31, 1997, File No. 0-8503.
(c)	Filed with SEMCO Energy, Inc.’s Form 10-Q for the quarter ended September 30, 2000, filed November 13, 2000, File No. 001-15565.
(d)	Filed with SEMCO Energy, Inc.’s Form 10-K for the fiscal year ended December 31, 2000, filed March 30, 2001, File No. 001-15565.
(e)	Filed with SEMCO Energy, Inc.’s Form 8-K filed June 21, 2001, File No. 001-15565.
(f)	Filed with SEMCO Energy, Inc.’s Form 10-Q for the quarter ended September 30, 2001, filed November 13, 2001, File No. 001-15565.
(g)	Filed with SEMCO Energy, Inc.’s Form 10-K for the fiscal year ended December 31, 2001, filed March 27, 2002, File No. 001-15565.
(h)	Filed with SEMCO Energy, Inc.’s Form 8-K filed September 20, 2002, File No. 001-15565.
(i)	Filed with SEMCO Energy, Inc.’s Registration Statement, Form S-4, No. 333-107200, filed July 21, 2003.
(j)	Filed as Appendix A to SEMCO Energy, Inc.’s 2004 Proxy Statement, filed April 6, 2004, pursuant to Rule 14a-6 of the Exchange Act, File No. 001-15565.
(k)	Filed with SEMCO Energy, Inc.’s Form 10-K for the fiscal year ended December 31, 2003, filed March 4, 2004, File No. 001-15565.
(l)	Filed with SEMCO Energy, Inc.’s Form 10-Q for the quarter ended March 31, 2004, filed May 7, 2004, File No. 001-15565.
(m)	Filed with SEMCO Energy, Inc.’s Form 10-Q for the quarter ended June 30, 2004, filed August 9, 2004, File No. 001-15565.
(n)	Filed with SEMCO Energy, Inc.’s Form 10-Q for the quarter ended September 30, 2004, filed November 9, 2004, File No. 001-15565.

103

(o)	Filed with SEMCO Energy, Inc.’s Form 8-K filed February 18, 2005, File No. 001-15565.
(p)	Filed with SEMCO Energy, Inc.’s Form 10-K for the fiscal year ended December 31, 2004, filed March 8, 2005, File No. 001-15565.
(q)	Filed with SEMCO Energy, Inc.’s Form 8-K filed March 17, 2005, File No. 001-15565.
(r)	Filed with SEMCO Energy, Inc.’s Registration Statement, Form S-3, No. 333-124005, filed April 11, 2005.
(s)	Filed with SEMCO Energy, Inc.’s Form 8-K filed July 1, 2005, File No. 001-15565.
(t)	Filed with SEMCO Energy, Inc.’s Form 10-Q for the quarter ended June 30, 2005, filed August 3, 2005, File No. 001-15565.
(u)	Filed with SEMCO Energy, Inc.’s Form 8-K filed September 19, 2005, File No. 001-15565.
(v)	Filed with SEMCO Energy, Inc.’s Form 10-Q/ A for the quarter ended September 30, 2005, filed January 10, 2006, File No. 001-15565.
(w)	To be filed in April 2006, pursuant to Rule 14a-6 of the Exchange Act, File No. 001-15565.

104

SIGNATURES

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

Semco Energy,Inc.

By  /s/George A. Schreiber, Jr.

George A. Schreiber, Jr.

President and Chief Executive Officer

(principal executive officer)

Date: March 14, 2006

      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 dates indicated.

Signature	Title	Date
/s/George A. Schreiber, Jr. George A. Schreiber, Jr.	President, Chief Executive Officer and Director	March 14, 2006
/s/Michael V. Palmeri Michael V. Palmeri	Senior Vice President, Treasurer and Chief Financial Officer (principal financial and accounting officer)	March 14, 2006
/s/John M. Albertine John M. Albertine	Director and Chairman	March 14, 2006
/s/John T. Ferris John T. Ferris	Director	March 14, 2006
/s/Harvey I. Klein Harvey I. Klein	Director	March 14, 2006
/s/Paul F. Naughton Paul F. Naughton	Director	March 14, 2006
/s/Edwina Rogers Edwina Rogers	Director	March 14, 2006
/s/Ben A. Stevens Ben A. Stevens	Director	March 14, 2006
/s/Donald W. Thomason Donald W. Thomason	Director	March 14, 2006
/s/John C. Van Roden, Jr. John C. Van Roden, Jr.	Director	March 14, 2006

105