Washington, D.C. 20549

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

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

For the transition period from ___to ___

(Exact name of registrant as specified in its charter)

Michigan		38-2144267
(State of incorporation)		(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)

		Name of each exchange on
Title of each class		which registered
Common Stock, $1 Par Value		New York Stock Exchange
10.25% Trust Preferred Securities		New York Stock Exchange

 

 

TABLE OF CONTENTS

INFORMATION ABOUT FORWARD-LOOKING STATEMENTS

This 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. Although the Company believes that the expectations reflected in these forward-looking statements are reasonable, the Company cannot provide 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 1 of this Form 10-K and include:

	•	the effects of weather and other natural phenomena;
	•	the economic climate and growth in the geographical areas where the Company does business;
	•	the capital intensive nature of the Company’s business;
	•	increased 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;

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	•	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 for the cost of doing business, including the cost of capital, and the amount of any cost disallowances;
	•	the Company’s ability to procure its gas supply on reasonable credit terms;
	•	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 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; and
	•	changes in the performance of certain assets, which could impact the carrying amount of the Company’s existing goodwill.

     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 southeastern Michigan. It was founded in 1950 as Southeastern Michigan Gas Company. In 1977, Southeastern Michigan Gas Enterprises, Inc. was formed as a holding company, into which Southeastern Michigan Gas Company was transferred. On April 24, 1997, Southeastern Michigan Gas Enterprise’s name was changed to 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.

     In prior years, the Company reported the following reportable business segments: (1) gas distribution; (2) construction services; (3) information technology services; and (4) propane, pipelines and storage. The information technology services segment and the propane, pipelines and storage segment did not meet the quantitative thresholds required to be reported as reportable business segments. However, previous management voluntarily elected to disclose information about these segments.

     Beginning with this Form 10-K, the Company will report one reportable business segment: gas distribution. This change is the result of the Company’s new strategic direction. In 2003 and 2004, the Board of Directors decided to focus the Company on its natural gas distribution business. This new strategic focus is reflected in the business segment reporting now used by the Company. 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 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 natural gas storage facilities. For information on the change in business segments and business segments in general, refer to Note 11 of the Notes to the Consolidated Financial Statements in Item 8 of this Form 10-K. For further information regarding the Company’s business strategy, refer to the caption “Business Strategy Summary” in Item 7 of this Form 10-K.

     During the first quarter of 2004, the Company began to actively market its construction services business segment and consequently, began accounting for this segment as a discontinued operation. On September 3, 2004, the Company sold substantially all the operating assets of its discontinued construction services business segment to InfraSource Services Inc. For further information on this divestiture, refer to Note 14 of the Notes to the Consolidated Financial Statements in Item 8 of this Form 10-K.

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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 operates as 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 operates as 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 on-main and near-main customers within the Company’s existing service territories. The Company will also seek expansion opportunities in and near these service territories, including acquisitions of, or investments in, natural gas distribution businesses and assets, pipelines and storage facilities.

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

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(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 period are determined by adding the degree days incurred during each day of that period. The Company determines the percent (%) that weather is warmer or colder than normal for a particular period by computing the deviation of actual degree days for that period from the average of degree days during the same periods in the prior fifteen years and dividing the deviation by such fifteen-year average. Degree days are an indicator of natural gas usage, since natural gas delivered by the Company is used by many customers for space heating, and heating usage is affected by how warm or cold it is.

     All revenue generated by the Gas Distribution Business for the years ended December 31, 2004, 2003, and 2002, 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 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 areas. The regulatory matters associated with gas distribution customers located in the City of Battle Creek and surrounding communities are subject to the jurisdiction of the City Commission of Battle Creek (“CCBC”). Regulatory matters for gas distribution 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 – 242,000; RCA – 118,000; and CCBC – 38,000. As part of a recent rate settlement with the CCBC, the CCBC may elect in the future to petition the MPSC to assume jurisdiction over customers located in the city of Battle Creek and nearby areas (the regulatory jurisdiction currently exercised by the CCBC). If the City so elects, the Company would jointly seek this jurisdictional change with the CCBC.

     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 91% of consolidated operating revenues in 2004, and 90% of consolidated operating revenues in both 2003 and 2002.

     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 general gas sales service to the Gas Customer Choice Program. The program was made available to a larger portion of the Company’s customer base in each of the years 2002, 2003 and 2004, such that by April 2004, the program was available to all gas sale 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, 2004. 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 may also purchase their 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 affected by commercial customers switching from gas sales service to gas transportation service. If customers elect to purchase gas from a different 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, 2004.

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 gas purchased by customers from third-party suppliers is then transported on the Company’s gas transmission and distribution network to the customers. Transportation services are also available to smaller volume customers who participate in the Gas Customer Choice Program described under the caption “Gas Sales.”

Customer Base. At December 31, 2004, the Gas Distribution Business had approximately 398,000 customers, including 280,000 customers in Michigan and 118,000 customers in Alaska. The largest concentration of customers in Michigan, approximately 117,000, is located in southeastern Michigan, just north of the metro-Detroit area. The remaining Michigan customers are located in various areas throughout the state, including Albion, Battle Creek, Holland, Houghton, Niles, Marquette, Ontangon, 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,

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Chugiak, Eagle River, Eklutna, Girdwood, Houston, Indian, Kasilof, Kenai, Knik, Nikiski, Palmer, Peters Creek, Portage, Sterling, Soldotna, Wasilla and Whittier. ENSTAR is the sole distributor of natural gas to the greater Anchorage metropolitan area, and its service area encompasses over 50% of the population of Alaska.

     The Gas Distribution Business’ customer base is diverse and includes residential, commercial and industrial customers. The largest customers include power plants, food production facilities, paper processing plants, furniture manufacturers, a liquefied natural gas plant, a fertilizer plant and others in a variety of industries. The average number of customers at SEMCO Gas has increased by an average of approximately 1.6% annually during the past three years, and the average number of customers at ENSTAR has increased by an average of approximately 3.2% annually during the past three years. However, average annual gas usage per customer has been decreasing slightly because, among other things, new homes and appliances are typically more energy efficient than older homes and appliances.

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 alternate energy source when 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 arises from alternate 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 shift production to other facilities if the price of natural gas and delivery services increase significantly. Natural gas has typically been less expensive than these alternative energy sources. However, over the past three years, natural gas prices have been volatile, making some of these alternative energy sources more economical than natural gas. 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 and connect directly to those pipelines. However, management is currently unaware of any significant bypass efforts by the Company’s customers. The Company has addressed, and would continue to address, any such efforts by offering flexible contract terms and additional services intended to retain these customers on the Company’s system. 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.

Natural Gas Supply. SEMCO Gas has agreements with BP Canada Energy Marketing Corp. (“BP”) covering the period of April 1, 2002, through March 31, 2005. The Company has separate agreements with BP related to customers in its service area regulated by the MPSC (“MPSC customers”) and customers in its service area regulated by the CCBC (“CCBC customers”).

     Under the BP agreement covering MPSC customers, BP provides gas supply portfolio management services as well as transportation and storage asset management services. The Company’s MPSC customers have paid for natural gas commodity costs through a gas cost recovery (“GCR”) pricing mechanism since April 1, 2002. The MPSC must approve the Company’s GCR gas purchase plans when the Company is operating under the GCR pricing mechanism. 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 2004, 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. For the MPSC customers, all 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” section within Note 1 of the Notes to the Consolidated Financial Statements in Item 8 of this Form 10-K.

     Under the BP agreement covering CCBC customers, BP provides all of the natural gas supply requirements for the CCBC customers as well as transportation and storage asset management services. Under the terms of the agreement, the price the Company pays to purchase natural gas for CCBC customers is fixed for the three-year period from April 1, 2002, through March 31, 2005. The Company entered into this fixed gas price supply contract because the CCBC authorized the Company to suspend its GCR pricing mechanism and utilize a fixed gas charge in the rates for CCBC customers until March 31, 2005. For information on how the GCR suspension and fixed gas charge program impact the cost of gas, refer to the “Cost of Gas” section within Note 1 of the Notes to the Consolidated Financial Statements in Item 8 of this Form 10-K.

     The Company does not plan to enter into another long term fixed priced supply agreement for the CCBC customers unless and until natural gas prices fall and the CCBC approves such a program. On February 15, 2005, the CCBC reinstated the GCR pricing mechanism, to be effective April 1, 2005. For the CCBC customers, all supplies purchased during each GCR period will be based on a portfolio of short-term fixed priced and short-term index priced supply agreements.

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     During 2004, the Company solicited bids for transportation and storage asset management services for the MPSC customers and the CCBC customers for another three-year term beginning on April 1, 2005. BP was the successful bidder for these services. The Company and BP are currently negotiating the terms of a new agreement.

     SEMCO Gas has access to natural gas supplies throughout the United States and Canada via major interstate and intrastate pipelines that run through 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 36% of the Company’s 2004 annual gas sales volumes in Michigan. SEMCO Gas Storage Company, a subsidiary of the Company, is a 50% owner of the ERGSS.

     ENSTAR has access to natural gas supplies in close proximity to its Anchorage, Alaska-area service territory. ENSTAR’s system, including the APC pipeline, 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 “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 15 Bcf of gas in 2005. Each year thereafter, Marathon’s maximum delivery obligation decreases by 2 Bcf per year until 2010 when it is 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.

     ENSTAR has an RCA-approved gas purchase contract with Anchorage Municipal Light and Power, Chevron U.S.A., Inc. and ConocoPhillips Alaska, Inc. that provides for the delivery of gas through the year 2009 from the Beluga natural gas field (the “Beluga Contract”). ENSTAR’s obligation to take gas under the Beluga Contract is estimated to be approximately 1.6 Bcf in 2005, 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 agreement provides that Aurora Gas will supply a portion of ENSTAR’s needs through 2016. Aurora is required to deliver up to 1.9 Bcf of natural gas in 2005. Aurora’s requirement begins declining annually in 2006 until the projected final year requirement of 0.2 Bcf in 2014. The total remaining commitment at the end of 2004 is 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 began in 2004. The Unocal Contract provides that Unocal will supply all of ENSTAR’s natural gas requirements not met by the 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 2004, Unocal made a commitment to supply all of ENSTAR’s requirements (not met by the Marathon, Beluga and Moquawkie contracts) through 2008 and to supply 16 Bcf in 2009 (which is estimated to be approximately 6 Bcf less than total requirements for that year). In any year after 2009, 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 a 36-month daily average price of certain traded natural gas futures contracts, subject to a floor price. The Unocal Contract also provides for reimbursement to Unocal of severance taxes and other charges.

     The Unocal, Marathon, Beluga and Moquawkie Contracts collectively are scheduled to supply all of ENSTAR’s requirements through 2008. After 2008, natural gas will still be available under those contracts 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. ENSTAR is currently in discussions with several parties to secure additional natural gas from the Cook Inlet area natural gas fields.

     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 proved natural gas reserves according to 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 is a reserve life of approximately 10 years in the Cook Inlet area, although shortages of daily deliverability could occur earlier. 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.

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     ENSTAR has been active in efforts to extend its supply of Cook Inlet area natural gas and to find other gas sources. Approximately 135 Bcf of natural gas is exported each year from Cook Inlet in the form of LNG and ammonia-urea fertilizer. The owner of the fertilizer plant recently announced that it expects that the plant would be closed in late-2005. That closure should make available to ENSTAR (and other users) gas that otherwise would have gone to the fertilizer plant. The export license for the LNG plant expires in 2009. If that license is not renewed, natural gas that would otherwise be exported by this plant should be available to Cook Inlet area users, including ENSTAR. In the negotiations with potential gas suppliers, ENSTAR also 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. 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 a campaign 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.

Environmental Matters. Prior to the construction of major 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 very 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 inital 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 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. For further information, refer to Note 13 of the Notes to the Consolidated Financial Statements in Item 8 of this Form 10-K.

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’s information technology (“IT”) services business uses existing information technology infrastructure and services required to support the Gas Distribution Business for non-affiliated customers, allowing the Company to realize additional revenue and income from its investment. The IT business provides IT services with a focus on mid-range computers, particularly the IBM I-Series (or AS-400) platform. Approximately 73% of the Company’s 2004 IT revenues came from services performed for affiliates. The Company has reorganized its IT business operation to focus it primarily on the Company’s IT needs and, while revenues from non-affiliated customers are expected to decline over time, the Company expects to continue to provide IT services to certain non-affiliated customers where it believes that it can leverage its existing infrastructure and services profitably. As part of the restructuring of its IT business operation, the Company decided to exit the residential internet service provider (“ISP”) portion of its ISP business. As a result of this decision, the Company recognized impairments of goodwill and fixed assets associated with that business. Refer to Note 1 of the Notes to the Consolidated Financial Statements in Item 8 of this Form 10-K for further information on the impairments.

     The Company owns a propane distribution business known as “Hotflame.” Hotflame supplies more than 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 the fuel 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 two 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 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 576 full-time employees at December 31, 2004, compared to 1,436 full-time employees at December 31, 2003. Approximately 269 of the employees at December 31, 2004, were members of collective bargaining units compared to 697 employees at December 31, 2003. The significant drop in the number of full-time and collective bargaining unit employees in 2004 when compared to 2003 is due to the sale of the Company’s discontinued construction services business in September 2004. For further information on this sale, refer to Note 14 of the Notes to Consolidated Financial Statements in Item 8 of this Form 10-K.

     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. 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 information the Company files with the SEC can also be obtained on the SEC’s website on the Internet at address http://www.sec.gov.

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 Securities and Exchange Commission, 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 the regulatory bodies may reduce the Company’s revenues and profitability.

     The Company is regulated by the Michigan Public Service Commission, or MPSC, the Regulatory Commission of Alaska, or RCA, and the City Commission of Battle Creek, Michigan, or CCBC. These regulatory bodies have jurisdiction over, among other things, rates, accounting procedures and standards of service. Approximately 98% of the Company’s revenues are generated by the regulated Gas Distribution Business. The actions of these regulatory bodies, including the possibility of a rate decrease, the failure to grant any requested rate increase, cost disallowances, the timing of any rate increase or any other action by them, may reduce the Company’s revenues and profitability.

The Company’s operations and earnings are weather sensitive and seasonal.

     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, the second and third fiscal quarters of the year. As a result, a mild winter in one of the Company’s service areas can have a significant adverse impact on demand for natural gas and, consequently, earnings and results of operations.

     Warmer than normal weather over the last several years has adversely affected the results of operations 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 0.3% and 0.9% warmer than normal during 2004 and 2002, respectively, and approximately 4.7% colder than normal during 2003. The temperature was approximately 6.0%, 8.0% and 7.8% warmer than normal in the Alaska service area during 2004, 2003 and 2002, respectively. The Company estimates that the combined impact of warmer or colder than normal temperatures in Michigan and Alaska reduced the gas sales margin of the gas distribution business by approximately $3.9 million, $2.7 million and $5.9 million in 2004, 2003 and 2002, respectively.

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

     Consistent with other gas distribution utilities, there is potential risk for industrial customers and electric generating plants, located in close proximity to interstate natural gas pipelines, to connect directly to such pipelines, which would reduce the Company’s revenues. Although the Company is not currently aware of any significant bypass efforts by its customers, the Company can make no assurances that its customers will not bypass the Company or that the Company could successfully retain such customers by employing any special efforts.

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Earnings growth is substantially dependent on customer growth.

     Many of the Company’s customers are increasingly endeavoring to conserve on energy costs through utilizing energy-efficient heating devices, increased insulation, alternative energy sources and other means. Over the past several years, average annual gas usage has been decreasing slightly because, among other things, new homes and appliances are typically more energy efficient than older homes and appliances. Accordingly, the Company’s earnings growth is substantially dependent on customer growth and may be adversely affected if the Company is unable to achieve customer growth within existing service territories or add additional customers by expanding service territories.

Operating results may be reduced 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 impacts the amount of residential, industrial and commercial growth and gas use 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. Additionally, a weakening economy could adversely impact customer collections.

Volatility in the price of natural gas and alternative energy sources could reduce profits.

     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 may be able to use one or more alternative energy sources or shift production to other facilities if the price of natural gas and delivery services increase significantly. Natural gas has typically been less expensive than these alternative energy sources. However, over the past three years, natural gas prices have been volatile, making some of these alternative energy sources more economical than natural gas. During this period, certain of the Company’s large Michigan industrial customers 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 offered will outweigh the negative effects of gas price volatility. Should these customers convert their requirements to another form of energy, the Company’s revenue could be reduced.

Liquidity and earnings could be adversely affected by the cost of purchasing gas and related actions by regulatory bodies concerning gas pricing mechanisms.

     Pricing for the Company’s gas distribution services are governed in Michigan by an MPSC-approved gas cost recovery, or GCR, pricing mechanism and in Alaska by an RCA-approved gas cost adjustment, or GCA, pricing mechanism. Both of these pricing mechanisms are designed so that, in the absence of any cost disallowances, the Company’s cost of gas purchased is passed-through to its customers and, therefore, the Company does not recognize any income on the gas commodity charge portion of customer rates.

     These 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, any adjustment of rates under the GCR pricing mechanism process 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 to March GCR period. A reconciliation case is filed by June 30 of each year to reconcile actual gas purchases during the previous April to March 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.

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     Under the GCR and GCA pricing mechanisms, the gas commodity charge portion of customers’ gas rates is adjusted annually to reflect the estimated cost of gas purchased for the upcoming 12-month period. Any difference between actual allowed cost of gas purchased and the estimate is deferred as either a gas charge over- or under-recovery and included in customer rates during the next GCR or GCA period. A gas charge over-recovery occurs when 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 allowed over-recovery or under-recovery is included in the next annual adjustment to the gas charge portion of rates. The GCR and GCA may be adjusted more frequently than annually if it is determined that there are significant variances from the estimates used in the annual determination.

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

     ENSTAR’s Anchorage area gas supply system is not linked to major interstate and intrastate pipelines or 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. Production from the Cook Inlet 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, or Tcf, of total proved natural gas reserves according to 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 is a reserve life of approximately 10 years, although shortages of daily deliverability could occur earlier. 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 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.

     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. 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. 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.

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

     The Company’s rates and operations in its Gas Distribution Business are 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 volatility of natural gas prices in North America, the bankruptcy filings by certain energy companies and 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 the 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 the rating agencies. In addition, the FASB or the SEC could enact new accounting standards that could impact the way the Company is required to record revenues, 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 business or access to the capital markets.

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The Company may be required to recognize additional impairment charges which would reduce reported earnings and result in a default under its credit facility.

     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 which could impact the value of its business segments. 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 reported earnings in a period of such change. In addition, such charges would reduce the Company’s consolidated net worth and shareholders’ equity, increasing the Company’s debt to total capitalization ratio, which may result in a default under the Company’s credit facility.

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

     As of December 31, 2004, the Company had available approximately $111 million of net operating losses, or NOLs, with which to offset the imposition of 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 $103 million of its total NOLs in the future is limited. However, the Company believes that, based on the size of the limitation and projections of future taxable income, the Company will be able to utilize all of such 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. Future offerings by the Company coupled with changes in the ownership of the Company’s common stock (some of which will be beyond the Company’s control) could 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 built-in losses and tax credits. The magnitude of such limitations and their effect on the Company is very 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 such time.

The Company’s operations and business are subject to extensive 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 cleaning up, and damages 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.

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     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, the Company expects to incur costs associated with investigatory and remedial actions at seven Michigan sites that were formerly 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 the full extent of 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 rate proceedings or from insurance recovery, these costs could reduce earnings and harm the Company’s business.

     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 earnings and harm the Company’s business, particularly if those costs are not fully recoverable from customers through regulatory rate proceedings.

Substantial operational risks are involved in operating a natural gas distribution, pipeline and storage system and such operational risks could reduce the Company’s revenues and increase expenses.

     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, extensive property damage, 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 results of operation 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 increase expenses.

The Company is currently party to a proceeding before the RCA, the outcome of which is impossible to predict.

     The Company currently has pending before the RCA a proceeding concerning the investment in the Company’s Series B Convertible Preference Stock and Warrants by K-1 GHM, LLLP, an affiliate of k1 Ventures Limited, or K-1. By petition filed on June 17, 2004, the Company asked the RCA to rule that the purchase of such stock and Warrants by K-1, and the conversion or exercise of such stock and Warrants, as applicable, are not, and will not be, deemed a “Control Change” or otherwise constitute transactions requiring RCA approval. The Alaska Attorney General’s office has intervened in this proceeding, asserting, among other things, that (i) the Company’s issuance of the Series B Convertible Preference Stock and Warrants to K-1 resulted in a Control Change requiring prior approval by the RCA, (ii) such a Control Change does 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 ENSTAR’s base rates, using a 2005 test year and a new depreciation study for ENSTAR’s property. The

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Company believes 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 opposes 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. The Company cannot predict the outcome of such issues with any certainty.

Risks Relating to the Company’s Indebtedness and Capital Stock

The bank credit agreement and the indentures governing the Company’s existing debt contain restrictive covenants that may reduce the Company’s flexibility in its business operations and limit its growth.

     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 general 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;
	•	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; and
	•	detracting from the Company’s ability to successfully withstand a downturn in its business or the economy generally.

These covenants place constraints on the Company’s business and may adversely affect its growth, business, results of operations, liquidity and financial condition.

Failure to comply with the covenants in the Company’s bank credit agreement could lead to the acceleration of such debt and the Company then may have difficulty refinancing or otherwise repaying such indebtedness.

     Covenants contained in the Company’s bank credit agreement require maintenance of a minimum net worth (as calculated therein), which requirement was $213.3 million as of December 31, 2004 (subject to adjustments based on net income and certain issuances of stock); an interest coverage ratio of at least 1.25; and a debt-to-capitalization ratio of 0.65 or less. As of December 31, 2004, the Company was in compliance with all bank credit agreement covenants, with a net worth of $231.9 million, a fixed charge coverage ratio of 1.30 and a debt-to-capitalization ratio of 62.7%. If the Company’s operating results caused the Company to fail a covenant test, the Company would be required to seek covenant relief from the Company’s lenders under its credit facility or, if unsuccessful, seek other financing alternatives. The Company cannot provide assurance that it would be able to obtain such relief or financing alternatives. 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 its credit facility or any other instruments evidencing indebtedness 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

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indebtedness, which could result in a material adverse effect on the Company’s business, results of operation, liquidity and financial condition.

     Third parties may be deterred or prohibited from acquiring the Company’s capital stock, which could deprive the Company’s shareholders of the opportunity to gain a takeover premium and depress the Company’s stock price.

     Certain provisions of the Company’s organizational documents, as well as other statutory and regulatory factors, may have the effect of discouraging or preventing others from acquiring large blocks of the Company’s common stock, or making it difficult to do so, including the following:

	•	the Company’s articles of incorporation divide the Board into three classes that serve staggered terms;
	•	the Company’s directors may be removed only for cause and by the affirmative vote of a majority of the shares entitled to vote in the election of directors; and
	•	the Company’s Shareholder’s Rights Plan grants common shareholders the right to purchase shares of Series A Preference Stock upon the occurrence of certain triggering events (the purpose of the plan is to ensure that any potential purchaser of the Company must negotiate with the Company’s Board before an acquisition).

     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 being deemed a public utility holding company and becoming subject to the Public Utility Holding Company Act of 1935, which would result in substantial increases in that entity’s administrative, legal and regulatory compliance costs and have similar adverse consequences for the Company.

The Company’s existing bank credit agreement is set to expire in June of 2005. To the extent the Company is unable to renegotiate the terms of its bank credit agreement, the Company’s results of operation and financial results could be adversely affected.

     The Company’s existing bank credit agreement is set to expire on June 25, 2005, however, the Company anticipates that in the near-term it will enter into an amendment of the current bank credit agreement to, among other things, extend the expiration of the bank credit agreement to September 2005. At December 31, 2004, there was approximately $13.0 million in letters of credit outstanding on the credit facility and approximately $39.3 million in borrowings outstanding, leaving approximately $61.9 million of the bank credit agreement unused. Even after giving effect to the proposed amendment, in order to provide additional working capital to finance the Company’s operations in the future, the Company will need to renegotiate its existing bank credit agreement to allow the Company more flexibility with respect to its ability to pay dividends and other distributions on its capital stock. The Company can make no assurance that it will be able to renegotiate its credit agreement on terms that will provide the Company with this additional flexibility, if at all. If the Company is unable to negotiate favorable terms, the Company’s business, results of operations, liquidity and financial condition could be adversely affected.

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, results of operation, liquidity and financial condition.

     Since March 2003, Moody’s Investors Service, Inc. has 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-. While both Moody’s Investors Service, Inc. and Standard & Poor’s Ratings Group have removed the “negative outlook” in conjunction with their ratings, 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

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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 prior downgrades noted above, two of the pipelines the Company utilizes have required prepayment for their services, one gas supplier has required the Company to pay multiple times in the month of delivery and other gas suppliers have requested prepayment or letters of credit. No assurance can be provided that customers and other suppliers will not impose additional requirements or restrictions on the conduct of the Company’s business.

     No assurance can be provided 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, however, could adversely affect the Company’s business, results of operations, liquidity and financial condition.

The Company’s substantial indebtedness may reduce its profitability, limit its growth and diminish its ability to respond to changing economic conditions.

     The Company’s business is capital intensive and the Company has significant amounts of debt. At December 31, 2004, the Company had total short and long-term debt of $537.7 million. The Company’s substantial debt may adversely affect its business, results of operations, liquidity and financial condition. For example, the Company’s substantial debt may:

	•	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 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, 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 are now faced 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.

     The Company is subject to interest rate risk in connection with the issuance of variable and fixed-rate debt. 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 effectively manage its risks. If the Company is unable to do so, its earnings may be reduced.

ITEM 2. PROPERTIES

GAS DISTRIBUTION BUSINESS SEGMENT

The gas delivery system of SEMCO Gas included approximately 160 miles of gas transmission pipelines and 5,529 miles of gas distribution mains and service lines at December 31, 2004. The pipelines, mains and service lines are located throughout the southern half of Michigan’s lower peninsula (centered in and around the cities of Port Huron, Albion, Battle Creek, Three Rivers, Niles and Holland) and also in the central and western areas of Michigan’s upper peninsula. At December 31, 2004, ENSTAR’s gas delivery system included approximately 393 miles of gas transmission pipelines and 2,527 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 properly 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 information technology 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, leasehold improvements, office equipment, telecommunications equipment and computer equipment. The building is located in Marysville, Michigan, and the remaining property is located in that building and in leased office space in Port Huron, Michigan.

     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 all 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 $6.4 million at December 31, 2004. 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, 2004:

     The Litchfield Lateral is a 31-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 an 17-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 a 37-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, and leased 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 late March 2003, the Company was named in a putative class-action lawsuit alleging that approximately 30 defendants, including SEMCO Energy, Inc. and SEMCO Energy Ventures, Inc., engaged in practices that violated the Sherman Antitrust Act and tortiously interfered with the business of the plaintiffs. In October 2003, the plaintiff voluntarily dismissed this action in the jurisdiction in which the action was originally filed and gave the Company notice that it would refile the complaint in a different jurisdiction. In November 2003, the plaintiff filed a separate but similar lawsuit against SEMCO Energy Services, Inc., a company subsidiary no longer actively engaged in business and whose operations were sold in 1999. This lawsuit was voluntarily dismissed by the plaintiff in July 2004. A variation of the aforementioned putative class action lawsuit was filed in July 2004. Neither the Company nor any of its subsidiaries were named as defendants. In October 2004, plaintiffs filed an amended complaint naming, among others, SEMCO Energy Services, Inc. and SEMCO Pipeline Company, as additional defendants. The amended lawsuit alleges violations of the Sherman Antitrust Act, the West Virginia Antitrust Act and various common law claims.

     In September 2003, the Company entered into a Purchase and Sale Agreement, dated September 16, 2003, to sell its wholly-owned subsidiary, APC, to Atlas Pipeline Partners, L.P. (“Atlas”) for $95 million (the “Agreement”). Pursuant to the Agreement, in October 2003, the Company and Atlas filed an application with the RCA seeking its final order approving the transfer, a special contract and certain other elements of the transaction specified in the Agreement and in the application. Several other parties intervened in this proceeding before the RCA and, as a result of negotiations, on March 26, 2004, the Company, Atlas and the interveners submitted to the RCA a stipulation attaching a proposed final order (“PFO”), which the parties requested that the RCA enter in this matter. After a hearing, the RCA on April 20, 2004 issued Order U-03-91(4) on the stipulation, which approved the transfer but which was not in the form of the requested PFO and did not on its face appear specifically to grant certain other approvals required by the agreement and sought by all parties. On May 5, 2004 the Company filed a motion with the RCA seeking, on an expedited basis, clarification (or, in the alternative, reconsideration) of its order. In response, on June 4, 2004, the RCA issued Order U-03-91(5) entitled “Order Granting Reconsideration, Vacating Order U-03-91(4), Rejecting Stipulation, Approving Transfer of Control, Allowing Parties to Request Further Proceedings, and Finding Motions For Expedited Consideration Moot,” which vacated the prior order and explicitly refused to grant four of the five regulatory approvals required for closing the transaction.

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     Following further discussion with Atlas, by letter dated July 1, 2004, the Company gave notice of termination of the Agreement. As a result, the Company recorded with respect to the second quarter of 2004, a write-off of expenses that it had incurred in connection with the proposed transaction amounting to approximately $1 million.

     In response to the Company’s notice, on July 23, 2004, Atlas initiated an arbitration proceeding with the American Arbitration Association, alleging that the Company breached and wrongfully terminated the Agreement and seeking compensatory damages from the Company of not less than $94.3 million. On December 31, 2004, Atlas and the Company entered into a settlement under which, among other things, the Company agreed to pay Atlas $5.5 million. Both parties executed claims releases, and neither party admitted any wrongdoing or liability related to the dispute. During the third and fourth quarter of 2004, the Company incurred $1.9 million in expenses associated with the arbitration proceeding and related settlement. The Company will continue to own and operate APC.

     In connection with the issuance of Convertible Preference Stock (“CPS”) and warrants (“Warrants”) to K-1 GHM, LLLP, an affiliate of the private equity firm k1 Ventures Limited (“K-1”), during 2004, the Company agreed to seek certain rulings from the RCA. This obligation would be satisfied if the RCA: (i) finds that the purchase of the CPS and Warrants by K-1, and the conversion or exercise of the CPS or Warrants, as applicable, are not, and will not be, deemed an acquisition of controlling interest in a corporation holding a certificate of public convenience and necessity (a “Control Change”) or otherwise constitute transactions requiring RCA approval; (ii) declares that RCA approval of such transactions is not required; or (iii), if the Company so elects, approves the Control Change. If the Company does not obtain such rulings from the RCA prior to March 19, 2005, among other things, the dividends payable on the CPS (which are currently at 6%) increase 1%, by quarter, subject to a cap of 12%, until such rulings are received. Under terms of the CPS, the Company also has the right, in the event such rulings are not obtained by March 19, 2005, and subject to certain conditions, to repurchase the CPS for $1,000 per share plus accrued but unpaid dividends and the cash value of dividends that would have been paid on the CPS over the following 12 months.

     By petition filed on June 17, 2004, the Company asked the RCA to rule that the purchase of the CPS and Warrants by K-1, and the conversion or exercise of the CPS or Warrants, as applicable, are not, and will not be, deemed a Control Change or otherwise constitute transactions requiring RCA approval. On September 22, 2004, the RCA issued an order finding that the RCA did not have the authority to make the requested determination without the Company’s filing an application for approval of a Control Change. On October 7, 2004, the Company asked the RCA to reconsider its order, on an expedited basis. On November 23, 2004, the RCA denied the Company’s Petition for Reconsideration and ordered a new docket to be opened in order to develop a sufficient record to allow a determination to be made as to whether the financing provided by K-1 constituted a Control Change or otherwise required RCA approval. The Alaska Attorney General has intervened in this docket, asserting in his initial comments, 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 does 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 ENSTAR’s base rates, using a 2005 test year and a new depreciation study for ENSTAR’s property. The Company believes 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 opposes 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.

     In 1999, the Company acquired an underground construction services business in Georgia as part of expanding its operations to include non-utility businesses. The assets of this business were subsequently sold in September 2004. The acquisition agreement for this business contained an indemnification provision by which the sellers agreed to reimburse the Company for all costs and expenses associated with certain claims. One of these claims involves a recently-affirmed judgment for approximately $0.8 million. The sellers have contested the Company’s right to indemnification under the acquisition agreement and declined to reimburse the Company for its payments of approximately $1.2 million in connection with this judgment, including attorneys’ fees and costs. In February 2005, the Company filed an action in federal district court in Georgia to recoup amounts owed the Company under the indemnification provision.

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 2004.

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PART II

ITEM 5. MARKET FOR THE REGISTRANT’S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS

MARKET INFORMATION

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 2004 and 2003, as reported on the NYSE.

     At February 28, 2005, the closing price of the Company’s common stock was $6.21 per share and the Company had 28,430,653 shares of common stock outstanding and had 8,261 registered common shareholders.

DIVIDENDS

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

UNREGISTERED SECURITIES

During 2004, the Company issued an aggregate of 9,370 shares of unregistered common stock, valued at approximately $55,823, to members of the Company’s Board of Directors pursuant to equity compensation plans 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. Information about the issuance of other unregistered equity securities during 2004 was included in the Company’s quarterly reports on Form 10-Q.

ITEM 6. SELECTED FINANCIAL DATA

     The following table sets forth selected financial and operating data. The selected financial data presented below as of December 31, 2000 and 2001, and for the years 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 and 2004, and for each of the three years in the period ended December 31, 2004, have been derived from the Company’s consolidated financial statements that were audited by PricewaterhouseCoopers LLP. You should read the selected financial data presented below in conjunction with the Company’s consolidated financial statements, the notes to the Company’s consolidated financial statements and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” appearing in Items 7 and 8 of this Form 10-K.

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SELECTED FINANCIAL DATA

---

(a)	Effective January 1, 2004, the Company began accounting for the construction services segment as a discontinued operation. Accordingly, for all years presented, its operating results are segregated and reported as discontinued operations in the Consolidated Statements of Operations. For further information on this reclassification and the sale of the assets of the construction services businesses, see Note 14 of the Notes to the Consolidated Financial Statements in Item 8 of this Form 10-K.
(b)	At year end.
(c)	Includes current maturities of long-term debt.
(d)	Includes company-obligated mandatorily redeemable trust preferred securities for 2002 and prior years.
(e)	Includes $8,398,000 of expenses related to terminated sale of subsidiary and a $152,000 goodwill impairment charge.
(f)	Includes debt exchange and extinguishment expenses of $24,030,000.
(g)	Includes $3,005,000 for restructuring and asset impairment charges.

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ITEM 7. MANAGEMENT’S DISCUSSION & ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

BUSINESS STRATEGY SUMMARY

     The Company is now primarily a natural gas distribution company with operations in Michigan and Alaska. This results from the Company’s sale of its construction services business and the restructuring of the Company’s information technology services business during 2004. The Company provides natural gas service to approximately 398,000 customers, with approximately 280,000 customers in Michigan and 118,000 customers in Alaska. Approximately 90% of the Company’s market is residential customers. The Company’s business is seasonal. 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 in the non-heating season 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 is two-fold. The Company is seeking to improve its financial situation, which includes improving its credit quality, increasing operating earnings and cash flow, and increasing its financial flexibility. In 2004, this effort included issuing $50 million of CPS and Warrants and calling $30 million of long-term debt. In June 2004, the Company suspended the common stock dividend, with the objective of supplementing free cash flow. The decision to suspend the dividend also 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. The effort to improve the Company’s financial situation also included the sale of the Company’s construction services business for $21.3 million. This transaction was consummated in September 2004 and ended ongoing operating losses associated with that business that had adversely affected the Company’s financial performance. In addition, the settlement of the arbitration between the Company and Atlas in December 2004 resolved a significant financial uncertainty for the Company.

     In 2005, the Company looks to further improve its financial situation by achieving satisfactory results in base rate increase requests in Michigan. The Company currently has an $11.65 million annual base rate increase request pending before the MPSC. In the Company’s Battle Creek, Michigan service area, in February 2005, the CCBC approved an annual base rate increase totaling $3.55 million, beginning April 2005, with additional base rate increases of $150,000 to be put into effect beginning April 1, 2006, and 2007, respectively, subject to certain conditions, including the Company making annual contributions to assist low income customers in paying their bills for natural gas service. Improvement in the Company’s financial situation also depends on issuing and redeeming securities on reasonable terms during 2005, as appropriate, and controlling expenses (including capital expenditures and operations and maintenance expenses).

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     In addition, the Company intends to grow its natural gas distribution business (including related pipeline and storage operations) by seeking to make appropriate acquisitions and investments in Michigan, Alaska, and elsewhere. Its ability to make such acquisitions and investments will be affected by efforts to improve the Company’s financial situation as well as by the availability of appropriate acquisition and investment opportunities and the ability to consummate any such transactions on reasonable terms. In December 2004, the Company entered into an agreement to acquire Peninsular Gas Company for $3.1 million, which, if this transaction is consummated, would add approximately 3,900 customers in the upper peninsula of Michigan. A request related to rate matters was approved by the MPSC on February 24, 2005. The Company expects to close on this transaction prior to November 1, 2005. This is a small acquisition, but illustrative of the Company’s current strategic direction.

     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 the natural gas distribution 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.

SUMMARY OF RESULT OF OPERATIONS

     The discussions in this section are summarized and intended to provide a high-level overview of the results of operations of the Company. In most instances, the items discussed here are covered in greater detail in later sections of Management’s Discussion and Analysis. 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:

     The $8.4 million net loss for 2004 is a $21.6 million improvement over 2003 results. The primary factors contributing to this improvement were a $15.5 million decrease in losses from the Company’s discontinued construction services business, the non-recurrence in 2004 of an expense recorded in 2003 of $24.0 million, or $15.0 million net of income taxes, for debt exchange and

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extinguishment costs, and a change in estimate of prior years’ state income taxes, which resulted in an additional income tax benefit of $2.2 million in 2004. The Company does not expect further losses from the construction services business after 2004, as substantially all the operating assets of this business were sold during 2004. The reduction in losses from the discontinued operations was partially offset by a decrease in operating income from the Company’s continuing operations of $15.2 million, or approximately $9.5 million net of income taxes, and an increase in financing costs of approximately $1.8 million net of income taxes. Approximately $8.4 million of the decrease in operating income was due to $2.9 million in costs associated with the Atlas arbitration proceeding and a payment of $5.5 million to settle the matter. The Company does not expect to incur any significant costs associated with the arbitration proceeding after 2004. The change in financing costs consists of dividends on the CPS that was issued in 2004, partially offset by a net decrease in interest expense and dividends on trust preferred securities.

     The net loss of $30.0 million for 2003 represents a decrease of $38.9 million from the net income of $8.9 million reported for 2002. The most significant items contributing to the decrease in results for 2003 were a $21.6 million increase in losses from the Company’s discontinued construction services business and an expense of $24.0 million, or $15.0 million net of income taxes, for debt exchange and extinguishment costs. The losses associated with the Company’s discontinued construction services business included charges of $20.4 million, or $17.4 million net of income taxes, for impairment of goodwill and fixed assets. The debt exchange and extinguishment costs were make-whole premiums and similar items associated with the refinancing and exchange of a significant portion of the Company’s debt. As a result of this refinancing, the Company does not have any significant amounts of long-term debt maturing until 2008. Also contributing to the decrease in operating results for 2003 was a net increase in financing costs (interest expense and dividends on trust preferred securities) of approximately $1.8 million net of income taxes and a decrease in operating income from the Company’s continuing operations of $0.7 million, or $0.5 million net of income taxes.

     The business segment analysis and other discussions on the next several pages provide additional information regarding the differences in operating results when comparing 2004, 2003 and 2002.

THE IMPACT OF WEATHER

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

     The Company estimates the impact of weather on its operating results by comparing actual gas consumption per customer during a period to the average of weather-normalized customer gas consumption during previous periods. The difference is multiplied by the average number of customers during the period to arrive at the total estimated increase or decrease in consumption associated with weather. The total increase or decrease in consumption is multiplied by the actual margin per unit of consumption during the period to arrive at the estimated impact of weather on operating results for the period. The weather-normalized customer consumption used in this calculation is determined by multiplying actual customer gas consumption during a particular period by a ratio, the numerator of which is an average of degree days during the same periods in the prior fifteen years, and the denominator of which is the actual degree days for that period.

     The Company determines the percent (%) that weather is warmer or colder than normal for a particular period by computing the deviation of actual degree days for that period from the average of degree days during the same periods in the prior fifteen years and dividing the deviation by such fifteen-year average. 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 period are determined by adding the degree days incurred during each day of that period.

     In the Company’s Michigan service area, weather was approximately 0.3% and 0.9% warmer than normal during 2004 and 2002, respectively, and approximately 4.7% colder than normal during 2003. Weather was approximately 6.0%, 8.0% and 7.8% warmer than normal in the Company’s Alaska service area during 2004, 2003 and 2002, respectively. The Company has estimated that the combined impact of warmer or colder than normal temperatures in Michigan and Alaska reduced the gas sales margin of the Gas Distribution Business by approximately $3.9 million, $2.7 million and $5.9 million in 2004, 2003 and 2002, respectively. Adjusted for income taxes, the estimated reduction was approximately $2.4 million, $1.5 million and $3.6 million, respectively, in those years.

CHANGES TO 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.” In prior years, the Company reported the following reportable business segments: (1) gas distribution; (2) construction services; (3) information technology services; and (4) propane,

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pipelines and storage. The information technology services segment and the propane, pipelines and storage segment did not meet the quantitative thresholds required to be reportable business segments. However, previous management voluntarily elected to disclose information about these segments.

     Beginning with this Form 10-K, the Company will report one reportable business segment: gas distribution. This change is the result of the Company’s current strategy and focus on its Gas Distribution Business. 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 Business 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 Sales Revenue. The Company’s gas sales revenue was $463.4 million, $427.9 million and $335.7 million for 2004, 2003 and 2002, respectively. The primary factor causing the change in gas sales revenue from year-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 under regulatory body-approved GCR and gas cost adjustment (“GCA”) 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 the GCR and GCA mechanisms, customers are charged rates that allow the Company to recoup its cost of gas purchased for sale to customers, subject, in Michigan, to a review by the MPSC of the Company’s GCR gas purchase plan and actual purchases. 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 the GCR and GCA mechanisms, in the absence of gas cost disallowances, for any allowed 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” 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 and GCA mechanisms. Management generally evaluates changes in gas sales margin rather than gas sales revenue due to the large 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,		2004				2003				2002
($ in thousands)
Gas sales revenues		$	463,356			$	427,936			$	335,655
Cost of gas sold			346,241				308,919				220,422
Gas sales margin		$	117,115			$	119,017			$	115,233
Gas transportation revenue			29,071				27,737				25,707
Other operating revenue			5,822				7,216				3,911
		$	152,008			$	153,970			$	144,851
Operations and maintenance			60,779				58,935				50,304
Depreciation and amortization			25,925				25,528				25,342
Property and other taxes			12,544				10,285				10,019
Operating income		$	52,760			$	59,222			$	59,186
Volumes of gas sold (MMcf)			66,165				67,272				65,057
Volumes of gas transported (MMcf)			56,619				51,358				44,921
Number of customers at year end			398,225				390,677				383,298
Average number of customers
Gas sales customers			391,495				384,459				375,997
Transportation customers			1,540				1,481				2,391
			393,035				385,940				378,388
Degree Days
Alaska			9,573				9,384				9,392
Michigan			6,726				7,063				6,668
Percent colder (warmer) than normal
Alaska			(6.0	)%			(8.0	)%			(7.8	)%
Michigan			(.3	)%			4.7	%			(.9	)%

     Gas Sales Margin. The Company’s gas sales margin is derived primarily from customer service fees and usage-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 impacted gas sales margin over the past three years and may impact future gas sales margin. These factors are changes in: (1) customer gas consumption; (2) the number of gas sales customers; (3) unaccounted-for gas; and (4) customer rates and gas cost savings.

     Changes in customer gas consumption from one year to another are attributable primarily to the impact of changes in temperatures between periods. However, 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) also contribute to changes in customer gas consumption. A decrease in customer gas consumption reduced gas sales margin for 2004 by approximately $2.3 million, when compared to 2003. An increase in customer gas consumption from 2002 to 2003 increased gas sales margin for 2003 by approximately $0.6 million.

     The average number of gas sales customers in Michigan and Alaska combined has increased by an average of 2.5% annually during the past three years. During 2004, the Company’s average number of gas sales customers increased by 7,037. During 2003, the Company’s average number of gas sales customers increased by 8,462. However, 970 of the 2003 increase represented customers switching from transportation service to general gas sales service. The remaining increase of approximately 7,500 represents the average number of new gas sales customers added in 2003. Customer additions increased gas sales margin for 2004 by approximately $2.1 million, when compared to 2003. Customer additions from 2002 to 2003 increased gas sales margin for 2003 by approximately $2.2 million. Customers switching from transportation service to general gas sales service in 2003 increased gas sales margin for 2003 by approximately $0.4 million, when compared to 2002.

     Unaccounted-for 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 unaccounted-for gas, including gas used by compressor stations along the system, measurement errors, and small leaks. The annual unaccounted-for gas volumes of the Gas Distribution Business typically range from 0.5% to 1.4% of total gas volumes sold and transported. An increase in unaccounted-for gas decreased gas sales margin for 2004 by approximately $1.0 million, when compared to 2003. A decrease in unaccounted-for gas from 2002 to 2003 increased gas sales margin for 2003 by approximately $0.3 million. The cost of unaccounted for gas is affected by the underlying commodity cost and rate mechanisms employed to price unaccounted-for volumes and recover this cost from customers.

     Changes in customer rates and gas cost savings directly affect gas sales margin. A reduction in customer rates at ENSTAR was required by an order issued by the RCA based on a rate review. The rate reduction took effect in September 2002 and generally reduced annual gas sales margins at ENSTAR by approximately 3.6%. There was an increase in customer rates effective in May 2003, for MPSC customers. The rate increase for MPSC customers was the result of a settlement agreement reached with the MPSC. The rate increase generally increased annual gas sales margins generated from MPSC customers by approximately 4.8%. Under the terms of a third-party natural gas supply and management agreement for the Company’s service areas regulated by the CCBC, certain gas cost savings are passed through to the Company. Gas cost savings realized under this agreement can vary from year to year. This agreement expires on March 31, 2005, at that time, the Company’s service area regulated by the CCBC will begin using a GCR pricing mechanism and will no longer realize gas costs savings. The CCBC has approved new rates for CCBC customers, to be effective with the first customer billing cycle of April 2005, and the use of a GCR pricing mechanism, to be effective April 1, 2005. These approvals are the result of a rate case filing to recover in part, increases in operating and regulatory compliance expenses. The rate related revenue increase is expected to more than offset the loss of gas cost savings. 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 and GCA pricing mechanisms and gas cost savings, refer to the caption “Cost of Gas” in Note 1 of the Notes to the Consolidated Financial Statements in Item 8 of this Form 10-K.

     The remainder of the change in gas sales margin from 2003 to 2004, a decrease of $0.7 million, was due primarily to changes in rates and gas cost savings, as well as other miscellaneous factors. These same items also contributed to a change in gas sales margin from 2002 to 2003, an increase of $0.3 million.

     Gas Transportation Revenue. The Company provides gas transportation services to customers who typically consume large volumes of gas. These customers purchase their gas directly from third-party suppliers. The gas purchased by customers from third-party suppliers is then transported on the Company’s gas distribution system to the customers. 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 in transportation volumes and rates for commercial transport customers, as well as an increase in transportation volumes for industrial and power plant transport customers. During 2003, there was a $2.0 million increase in gas transportation revenue when compared to 2002. The primary causes of the increase were an increase in transportation volumes at ENSTAR, partially offset by the impact of a rate reduction at ENSTAR and customers switching from transportation service to gas sales service in Michigan. The customers switching from transportation services to gas sales services during 2002 and 2003 generally represent small volume customers who were participating in a special program similar to the Company’s Gas Customer Choice Program. When the special program ended in March 2002, the participating customers were obliged to utilize the Company’s gas sales service. For information on the Gas Customer Choice Program, refer to the caption “Gas Sales” in Item 1 of this Form 10-K.

     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. The miscellaneous customer revenues include various service fees and late payment fees charged to customers. An increase in these fees from 2003 to 2004 increased other operating revenue for 2004 by approximately $1.2 million. The change in these fees caused other operating revenue to increase by approximately $0.7 million for 2003, when compared to 2002.

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     The pipeline management revenue is earned by Norstar. These revenues increased approximately $2.5 million in 2003, when compared to 2002, because of revenues earned from Norstar’s management of a pipeline construction project completed in 2003. 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 the project Norstar managed in 2003.

     Operations and Maintenance Expenses. For the year 2004, operations and maintenance (“O&M”) expenses increased by $1.8 million when compared to 2003. During 2003, O&M expenses increased by $8.6 million when compared to 2002. The changes in operating expenses over the past three years resulted from four primary factors: (1) employee benefit costs; (2) professional fees; (3) commercial insurance and claims costs; and (4) uncollectible customer accounts.

     Employee benefit costs primarily include pension expense and medical coverage expense, including retiree medical coverage. For 2004, pension expense increased by approximately $0.2 million while medical coverage costs decreased by approximately $1.6 million. The decrease in medical coverage costs 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. For 2003, employee benefit costs increased by approximately $3.5 million, when compared to 2002.

     The changes in professional fees are due in large part to compliance with the Sarbanes-Oxley Act of 2002. Professional fees increased in 2004 by approximately $2.3 million, when compared to 2003. During 2003, professional fees increased by approximately $0.4 million, when compared to 2002.

     Commercial insurance and claims costs increased by approximately $0.7 million for 2004, when compared to 2003. For 2003, commercial insurance and claims costs increased by approximately $1.6 million, when compared to 2002. Commercial insurance costs have increased significantly over the past few years as a result of the September 11, 2001 attack, which has caused increases in liability insurance, and recent corporate financial wrongdoing by other large companies, which has increased director and officer 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 decreased by approximately $0.7 million in 2004, when compared to 2003. By comparison, during 2003, uncollectible customer accounts increased by approximately $1.5 million, when compared to 2002. The increase in 2003 was due primarily to local economic factors and a few large write-offs associated with customer bankruptcies. The decrease in uncollectible customer accounts in 2004 was primarily due to a reduction in large-customer bankruptcy write-offs.

     The remaining increase in O&M expenses from 2002 to 2003, and from 2003 to 2004, was caused by increases in 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. 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 of proceeds the Company expects to recover from certain prior years’ property tax appeals. Disregarding the $1.4 million adjustment, property taxes accounted for 71% to 74% of the amounts reported for property and other taxes during 2004, 2003 and 2002. 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 Financial Accounting Standards Board’s (“FASB”) Statement of Financial Accounting Standards (“SFAS”) 71, “Accounting for the Effects of Certain Types of Regulation,” refer to Notes 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” in Item 1 of this Form 10-K for information on competition in this business segment.

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CORPORATE AND OTHER

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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 $17.2 million for all three years, 2004, 2003 and 2002. The composition of these revenues was also essentially the same in 2004, when compared to 2003. However, the underlying revenues for 2003, when compared to 2002, did change by offsetting amounts. There was a $0.9 million increase in propane distribution revenues as a result of colder weather in the Company’s propane distribution service area and an increase in the market price for propane. This increase in revenues was offset partially by a $0.6 million decrease in information technology services revenues, primarily due to a decrease in IT projects with affiliated customers, and a $0.2 million decrease in rental revenues. The decrease in rental revenue related to a building owned by one of the Company’s subsidiaries and rented to Company affiliates. The building was sold in December 2002 and the Company leased the building from the purchaser until the Company moved into its new leased headquarters in 2005. The $17.2 million of operating revenues for corporate and other during 2004 consisted of $9.2 million of IT services revenue, $5.5 million of propane distribution revenue, $2.3 million of gas pipeline revenue, and $0.2 million in other miscellaneous revenue.

Operating Income. Corporate and other reported an operating loss of $7.3 million for 2004, compared to operating income of $1.5 million for 2003 and operating income of $2.2 million for 2002. The primary cause of the decrease in 2004, when compared to 2003, was $2.9 million in costs associated with the Atlas arbitration proceeding and a payment of $5.5 million to settle the matter. 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. The decrease during 2003, compared to 2002, was due primarily to a $0.5 million increase in corporate consulting and professional fees, the $0.2 million decrease in rental revenue discussed above, a $0.1 million increase in depreciation, and losses on the sale of equipment, partially offset by lower operating expenses and business taxes. The $7.3 million operating loss for corporate and other during 2004 consisted of approximately $9.6 million operating losses from the Company’s corporate division and other small operations, partially offset by $0.5 million of IT services operating income, $0.5 million of propane distribution operating income and $1.3 million of gas pipeline operating income.

OTHER INCOME AND DEDUCTIONS

     Interest Expense. Interest expense increased by $4.6 million in 2004, when compared to 2003, and increased by $9.7 million in 2003, when compared to 2002. Contributing to the increases were 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 Company-obligated mandatorily redeemable trust preferred securities (“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 during 2004 and $3.2 million of the increase during 2003. 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 was primarily due to higher levels of long-term debt, an increase in financing fees related to the Company’s short-term bank

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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 has a higher rate of interest than the Company’s short-term bank credit facility.

     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. 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 refinancing and the debt exchange and extinguishment costs, 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 2004, when compared to 2003, was primarily due to higher equity earnings from the Company’s investment in ERGSS, the Company’s gas storage partnership and an increase in allowance for funds used during construction, or AFUDC. The $0.2 million decrease in other income for 2003, when compared to 2002, was primarily due to the non-recurrence in 2003 of income from a project completed by the Company for a third-party in 2002, offset partially by higher equity earnings from ERGSS.

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 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, and the decrease in 2003, when compared to 2002. 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. As a result, the Company does not expect future losses from this business after 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. 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.

DIVIDENDS ON CONVERTIBLE PREFERENCE STOCK

     The Company issued CPS in the first and second quarters of 2004. These securities and the paid-in-kind, non-cash dividends on these securities are described in Note 4 of the Notes to the Consolidated Financial Statements. Non-cash dividends on the CPS were $3.2 million for the year ending December 31, 2004.

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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:

     Property additions for the Gas Distribution Business primarily represent gas service lines for new customers and, to a lesser extent, gas main and service line replacements. Property additions for the Gas Distribution Business increased $9.6 million during 2004, when compared to 2003. The primary reasons for the increase were a $5 million pipeline project for APC and $1 million spent on a new billing system for the Company. In 2005, the Company plans to spend approximately $40 million on Gas Distribution Business property additions. Property additions for corporate and other decreased $0.9 million during 2004, when compared to 2003. The primary reason for the decrease was the and sale of the Company’s construction services business. During 2002, the Company received $4.5 million in proceeds for the sale of two buildings and vacant land, net of costs. The two buildings housed a large portion of the operations and administrative personnel of SEMCO Gas. After the sale, these two facilities were leased by the Company until it moved into its new headquarters in 2005.

     Cash Flows Provided by Operations. The Company’s net cash provided by (used for) operating activities totaled $40.2 million in 2004, $(12.5) million in 2003 and $26.2 million in 2002. 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. As discussed in previous sections, the operating results of the Company’s discontinued construction services business decreased significantly over the past few years, which contributed to the decrease in cash provided by operating activities. This has been mitigated by a decrease in capital expenditures for equipment at the construction services business and proceeds received upon the sale of that business, which has caused a decrease in cash flows used for investing activities by the construction services business.

     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 has used significant amounts of short-term borrowings to finance natural gas purchases for storage during the non-heating season. 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.

     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, certain of the pipelines the Company utilizes have required prepayment for their services. During 2003, one gas supplier required the Company to pay multiple times in the month of delivery and other gas suppliers requested prepayment, escrow accounts or letters of credit. This shortened the Company’s accounts payable cycle compared to prior years and is one of the primary causes of the decrease in cash flows from operations during 2003. The other primary cause of the decrease in cash flows from operations during 2003 was an increase in the market price of natural gas purchased. As a result, the value of the Company’s gas in underground storage at December 31, 2003, was approximately $23.8 million higher than it was at December 31, 2002. The use of proceeds from the issuance of long-term debt in 2003 to reduce short-term borrowings helped free up the Company’s short-term credit facility for supplier required letters of credit and to finance the decrease in operating cash flows caused by the increasing price of gas and the shorter accounts payable cycle.

     The improvement in cash flows from operating activities in 2004 was due primarily the easing of the credit restrictions put in place during 2003 by certain of the pipelines and 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.

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     Cash Flows Provided by Financing. The Company’s net cash provided by (used for) financing activities totaled $(28.5) million, $40.9 million and $5.6 million in 2004, 2003 and 2002, respectively.

     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 ultimately 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.

     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 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, $0.40 and $0.59 in 2004, 2003 and 2002, 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.

     Future Financing. In general, capital expenditures are funded with operating cash flows and the utilization of short-term bank credit facilities. When appropriate, the Company expects to refinance its short-term debt with long-term debt, common stock or other long-term financing instruments. The Company has a short-term bank credit facility, which consists of a $69 million multi-year revolver and a $45.2 million 364-day facility, both of which were to expire in June 2005. The Company anticipates that in March 2005, the revolver will be reduced to $60.0 million, the 364-day facility will be reduced to $40.8 million and both facilities will be extended 90 days to expire in September 2005. The 364-day facility also has a one-year term loan option. At December 31, 2004, there was approximately $13.0 million in letters of credit outstanding on the bank credit facility and approximately $39.3 million in borrowings outstanding, leaving approximately $61.9 million of the bank credit facility unused. During the third quarter of 2005, the Company intends to refinance this facility with a multi-year revolving credit facility. Refer to Note 5 of the Notes to the Consolidated Financial Statements for additional information regarding the bank credit facility including a description of the covenants contained in the bank credit agreement.

     As discussed previously, in September 2004, the Company sold substantially all the assets of its construction services business to InfraSource Services, Inc. for approximately $21.3 million. The Company initially invested the net proceeds from the sale in cash equivalents, but has been using, and continues to use, the proceeds to fund capital expenditures. Refer to Note 14 of the Notes to the Consolidated Financial Statements for further information.

     In March 2000, a registration statement on Form S-3 (“registration statement”) filed by the Company and SEMCO Capital Trust I, SEMCO Capital Trust II and SEMCO Capital Trust III with the Securities and Exchange Commission (“SEC”) became effective. The Company and the capital trusts registered up to $500 million of securities under the registration statement, of which $467 million has been utilized to issue securities during 2003 and prior years. The remaining balance of $33 million under the registration statement is available for any future issuances of common stock, preferred stock, trust preferred securities and long-term debt, as needed. At the present time, the Company does not meet the requirements under its indentures to issue additional senior notes. Long-term debt of the Company scheduled to mature during the next five years includes $0.1 million of 3.77% notes due in 2005, $15 million of 6.50% notes due in 2005, $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. Additionally, $41.2 million of 10.25% subordinated notes due in 2040 become callable at par in April 2005.

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     The Company’s capital structure at December 31, 2004 was approximately 71.5% total debt (including current maturities and notes payable), 6.4% preference stock and 22.1% common equity. The Company is currently assessing 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. To this end, the Company’s financing plans currently contemplate the issuance of approximately $25 million of common equity in the second half of 2005. The intended use of proceeds from this issuance is to redeem at par a like amount of the Company’s 10.25% subordinated notes and related Trust Preferred Securities.

     In connection with the issuance of the CPS and Warrants to K-1 during 2004, the Company agreed to seek certain rulings from the RCA. This obligation would be satisfied if the RCA: (i) finds that the purchase of the CPS and Warrants by K-1, and the conversion or exercise of the CPS or Warrants, as applicable, are not, and will not be, deemed an acquisition of controlling interest in a corporation holding a certificate of public convenience and necessity (a “Control Change”) or otherwise constitute transactions requiring RCA approval; (ii) declares that RCA approval of such transactions is not required; or (iii), if the Company so elects, approves the Control Change. If the Company does not obtain such rulings from the RCA prior to March 19, 2005, among other things, the dividends payable on the CPS (which are currently at 6%) increase 1%, by quarter, subject to a cap of 12%, until such rulings are received. Under the terms of the CPS, the Company also has the right, in the event such rulings are not obtained by March 19, 2005, and subject to certain conditions, to repurchase the CPS for $1,000 per share plus accrued but unpaid dividends and the cash value of dividends that would have been paid on the CPS over the following 12 months. The RCA proceeding requesting such approvals is ongoing. The Company’s financing plans described above do not reflect any consequences arising from the RCA proceeding or otherwise in connection with this matter. In light of the foregoing, the Company is currently evaluating a near-term repurchase of the CPS and Warrants from K-1 and the financing that would be necessary in connection with such a transaction.

     Ratio of Earnings to Fixed Charges. The Company’s ratio of earnings to fixed charges, as defined under Item 503 of SEC regulation S-K, was 1.06 for 2004, less than a one-to-one coverage for 2003 and 1.46 for 2002. The amount of earnings that would be required to attain a ratio of one-to-one for 2003 was approximately $8.0 million. This ratio is more strictly defined than the fixed charges coverage ratio used to determine compliance with the debt covenants contained in the Company’s bank credit agreement. “Earnings,” as defined by Item 503, represents income (loss) before income taxes, interest expense and minority interest. “Fixed charges,” as defined by Item 503, represents interest expense and preferred securities dividend requirements of consolidated subsidiaries. The Company had such dividend requirements under its trust preferred securities and included them in the calculation of fixed charges for purposes of calculating the ratio required under Item 503.

     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 guarantees 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, 2004.

     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.

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MARKET RISK INFORMATION

     The Company’s primary market risk arises from fluctuations in commodity 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 GCA 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” 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 tables provide information about the Company’s financial instruments that are sensitive to interest rate changes as of December 31, 2004, and December 31, 2003:

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(a)		Amounts represent total credit available to us at December 31, 2004 rather than the actual amount outstanding at December 31, 2004.
(b)		The average interest rate reported for the variable rate bank credit facility is the average rate during the year ended December 31, 2004.

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(a)		Amounts represent total credit available to us at December 31, 2003 rather than the actual amount outstanding at December 31, 2003.
(b)		The average interest rate reported for the variable rate bank credit facility is the average rate during the year ended December 31, 2003.

IMPACT OF INFLATION

     The cost of gas sold in Michigan subject to the jurisdiction of the MPSC is recovered from customers through the GCR mechanism. The cost of gas sold in Alaska is recovered from customers through the GCA mechanism. The GCR and GCA 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. The Company has a fixed gas charge program in place until March 31, 2005, for customers located in the City of Battle Creek, Michigan, and nearby communities. Effective April 1, 2005, customers in the Company’s Battle Creek service area will pay for the cost of gas through a GCR mechanism that allows 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” in Note 1 of the Notes to the Consolidated Financial Statements in Item 8 of this Form 10-K for more information.

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     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. 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 United States. 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 which 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 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 2004 annual impairment test 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. 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, 2004, by $5.2 million and the aggregate of the service and interest cost components of net periodic retiree medical costs for 2004, 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.

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NEW ACCOUNTING STANDARDS

In December 2004, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 123 (revised 2004) – “Share-Based Payment.” Refer to the “Stock-Based Compensation” section of Note 1 of the Notes to the Consolidated Financial Statements in Item 8 of this Form 10-K for information on this new accounting standard.

     Also, in December 2004, the FASB issued SFAS No. 153 (SFAS 153), “Exchanges of Nonmonetary Assets an amendment of APB Opinion No. 29 (APB 29). This Statement addresses the measurement of exchanges of nonmonetary assets. It eliminates the exception from fair value measurement for nonmonetary exchanges of similar productive assets in paragraph 21(b) of APB 29 and replaces it with an exception for exchanges that do not have commercial substance. This Statement is effective for nonmonetary asset exchanges occurring in fiscal periods beginning after June 15, 2005. The Company does not believe the adoption of this Statement will have any material impact on the Company’s financial statements.

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

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.

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Report of Independent Registered Public Accounting Firm

To the Board of Directors and Shareholders of
SEMCO Energy, Inc.:

We have completed an integrated audit of SEMCO Energy, Inc.’s 2004 consolidated financial statements and of its internal control over financial reporting as of December 31, 2004 and audits of its 2003 and 2002 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 and cash flows present fairly, in all material respects, the financial position of SEMCO Energy, Inc. and its subsidiaries at December 31, 2004 and 2003, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2004 in conformity with accounting principles generally accepted in the United States of America. 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.

As explained in Note 4 to the financial statements, effective July 1, 2003, the Company changed its method of accounting for its trust preferred securities and associated minority interest (dividends on trust preferred securities) in accordance with SFAS No. 150, “Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity.” As explained in Note 4 to the financial statements, effective December 31, 2003, the Company changed its method of accounting for its capital trust subsidiaries in accordance with Financial Accounting Standards Board Interpretation No. 46R, “Consolidation of Variable Interest Entities, an Interpretation of ARB No. 51.”

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 9(A), that the Company maintained effective internal control over financial reporting as of December 31, 2004 based on criteria established in Internal Control — Integrated Framework issued 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, 2004, based on criteria established in Internal Control — Integrated Framework issued 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.

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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, 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.

PricewaterhouseCoopers LLP
Detroit, Michigan
March 8, 2005

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CONSOLIDATED STATEMENTS OF OPERATIONS

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

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CONSOLIDATED STATEMENTS OF FINANCIAL POSITION

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

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CONSOLIDATED STATEMENTS OF CASH FLOWS

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

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