Semco Energy (SEN) 10-Q 2006 Q3 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)
x	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the quarterly period ended September 30, 2006
	OR
o	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the transition period from _____________ to _____________

Commission file number 001-15565

SEMCO Energy, Inc.

(Exact name of registrant as specified in its charter)

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

810-987-2200

(Registrant's telephone number, including area code)

N/A

(Former name, former address and former fiscal year, if changed since last report)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such requirements for the past 90 days.   x Yes    o No  

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

Large accelerated filer o Accelerated filer x  Non-accelerated filer o

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

The number of outstanding shares of the Registrant’s common stock as of October 31, 2006: 35,426,386

TABLE OF CONTENTS FOR FORM 10-Q

For Quarter Ended September 30, 2006

		Page Number
Table of Contents for Form 10-Q		2
Information About Forward-Looking Statements		3
PART I - FINANCIAL INFORMATION
Item 1.	Financial Statements	4
Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	29
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	50
Item 4.	Controls and Procedures	50
PART II - OTHER INFORMATION
Item 1.	Legal Proceedings	51
Item 1A.	Risk Factors	51
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	51
Item 3.	Defaults upon Senior Securities	51
Item 4.	Submission of Matters to a Vote of Security Holders	51
Item 5.	Other Information	51
Item 6.	Exhibits	52
Signatures		53
Exhibit Index		54

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Information About Forward-Looking Statements

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

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

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

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

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

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

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

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

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

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

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

·   the amount and terms of the Company’s debt and its credit ratings;

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

·   the Company’s ability to maintain an effective system of internal control;

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

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

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

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

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

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PART I - FINANCIAL INFORMATION

Item 1.Financial Statements

  

SEMCO ENERGY, INC.
CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)
	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2006			2005			2006			2005
	(In thousands, except per share amounts)
OPERATING REVENUES
Gas sales	$	55,295		$	53,976		$	398,899		$	351,592
Gas transportation		5,556			5,552			21,101			20,761
Other		3,341			2,782			12,703			12,150
		64,192			62,310			432,703			384,503
OPERATING EXPENSES
Cost of gas sold		36,637			36,127			312,756			264,304
Operations and maintenance		17,713			17,784			56,911			54,025
Depreciation and amortization		7,201			7,094			21,568			21,219
Property and other taxes		2,505			3,039			7,735			9,403
		64,056			64,044			398,970			348,951
OPERATING INCOME (LOSS)		136			(1,734	)		33,733			35,552
OTHER INCOME (DEDUCTIONS)
Interest expense		(10,270	)		(10,712	)		(31,000	)		(32,648	)
Debt extinguishment costs		-			(1,090	)		-			(1,456	)
Other		664			856			2,027			2,004
		(9,606	)		(10,946	)		(28,973	)		(32,100	)
INCOME (LOSS) BEFORE INCOME TAXES		(9,470	)		(12,680	)		4,760			3,452
INCOME TAX (EXPENSE) BENEFIT		3,582			4,750			(1,486	)		(999	)
INCOME (LOSS) FROM CONTINUING OPERATIONS		(5,888	)		(7,930	)		3,274			2,453
DISCONTINUED OPERATIONS
Income from construction services operations, net of income tax expense of $312		-			538			-			538
NET INCOME (LOSS)		(5,888	)		(7,392	)		3,274			2,991
DIVIDENDS ON CONVERTIBLE CUMULATIVE PREFERRED STOCK		649			947			2,103			2,044
DIVIDENDS AND REPURCHASE PREMIUM ON CONVERTIBLE PREFERENCE STOCK		-			-			-			9,112
NET INCOME (LOSS) AVAILABLE TO COMMON SHAREHOLDERS	$	(6,537	)	$	(8,339	)	$	1,171		$	(8,165	)
EARNINGS (LOSS) PER SHARE - BASIC
Income (loss) from continuing operations	$	(0.18	)	$	(0.29	)	$	0.03		$	(0.30	)
Net income (loss) available to common shareholders	$	(0.18	)	$	(0.27	)	$	0.03		$	(0.28	)
EARNINGS (LOSS) PER SHARE - DILUTED
Income (loss) from continuing operations	$	(0.18	)	$	(0.29	)	$	0.03		$	(0.30	)
Net income (loss) available to common shareholders	$	(0.18	)	$	(0.27	)	$	0.03		$	(0.28	)
AVERAGE COMMON SHARES OUTSTANDING
Basic		35,341			31,089			34,526			29,346
Diluted		35,341			31,089			34,764			29,346
The accompanying condensed notes to the unaudited consolidated financial statements are an integral part of these statements.

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SEMCO ENERGY, INC.
CONSOLIDATED STATEMENTS OF FINANCIAL POSITION
(Unaudited)
ASSETS
	September 30,		December 31,
	2006		2005
	(In thousands)
CURRENT ASSETS
Cash and cash equivalents	$	1,599	$	4,124
Restricted cash		3,636		1,590
Receivables, less allowances of $2,922 and $1,758		20,684		64,584
Accrued revenue		14,850		71,615
Gas in underground storage, at average cost		102,650		93,065
Prepaid expenses		11,749		15,307
Deferred income taxes		6,355		5,345
Materials and supplies, at average cost		5,287		4,970
Regulatory asset - gas charges recoverable from customers		1,472		971
Other		608		1,114
		168,890		262,685
PROPERTY, PLANT AND EQUIPMENT
Gas distribution		764,131		735,052
Corporate and other		39,045		39,879
		803,176		774,931
Less - accumulated depreciation		214,706		197,543
		588,470		577,388
DEFERRED CHARGES AND OTHER ASSETS
Goodwill		143,374		143,374
Regulatory assets		14,385		12,602
Unamortized debt expense		8,398		10,057
Other		12,700		10,449
		178,857		176,482
TOTAL ASSETS	$	936,217	$	1,016,555
The accompanying condensed notes to the unaudited consolidated financial statements are an integral part of these statements.

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SEMCO ENERGY, INC.
CONSOLIDATED STATEMENTS OF FINANCIAL POSITION
(Unaudited)
LIABILITIES AND CAPITALIZATION
	September 30,			December 31,
	2006			2005
	(In thousands, except for number of shares and par values)
CURRENT LIABILITIES
Notes payable	$	32,500		$	78,900
Accounts payable		24,608			64,557
Customer advance payments		22,526			22,043
Regulatory liability - amounts payable to customers		8,324			12,281
Pension and other postretirement costs		7,100			7,100
Accrued interest		12,623			4,616
Other		9,539			8,806
		117,220			198,303
DEFERRED CREDITS AND OTHER LIABILITIES
Regulatory liabilities		60,523			59,214
Deferred income taxes		35,661			30,715
Customer advances for construction		17,170			17,263
Pension and other postretirement costs		4,299			3,490
Other		7,814			5,385
		125,467			116,067
LONG-TERM DEBT		442,171			441,659
CONVERTIBLE CUMULATIVE PREFERRED STOCK
$1 par value; 500,000 shares authorized; 239,216 and 350,000 shares outstanding		45,618			66,526
COMMON SHAREHOLDERS' EQUITY
Common stock - $1 par value; 100,000,000 shares authorized; 35,411,296 and 33,704,025 shares outstanding		35,411			33,704
Capital surplus		249,924			241,944
Unearned compensation associated with restricted stock		-			(795	)
Accumulated comprehensive income (loss)		(8,985	)		(9,073	)
Retained earnings (deficit)		(70,609	)		(71,780	)
		205,741			194,000
TOTAL LIABILITIES AND CAPITALIZATION	$	936,217		$	1,016,555
The accompanying condensed notes to the unaudited consolidated financial statements are an integral part of these statements.

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SEMCO ENERGY, INC.
CONSOLIDATED STATEMENTS OF CASH FLOW
(Unaudited)
	Nine Months Ended
	September 30,
	2006			2005
	(In thousands)
CASH FLOWS PROVIDED BY (USED FOR) OPERATING ACTIVITIES
Net income	$	3,274		$	2,991
Adjustments to reconcile net income to net cash provided by (used for) operating activities:
Depreciation and amortization		21,568			21,219
Amortization of debt costs and debt basis adjustments included in interest expense		2,565			2,668
Deferred income taxes and amortization of investment tax credits		3,936			684
Non-cash share-based compensation		1,365			570
Debt extinguishment costs		-			1,456
Changes in operating assets and liabilities and other, excluding the impact of business acquisitions and divestitures:
Receivables, net		43,900			20,512
Accrued revenue		56,764			42,640
Prepaid expenses		3,558			2,581
Materials, supplies and gas in underground storage		(9,901	)		(34,424	)
Regulatory asset - gas charges recoverable from customers		(501	)		(1,243	)
Accounts payable		(39,949	)		(13,685	)
Customer advances and amounts payable to customers		(3,567	)		7,189
Other		10,816			5,439
NET CASH PROVIDED BY OPERATING ACTIVITIES		93,828			58,597
CASH FLOWS PROVIDED BY (USED FOR) INVESTING ACTIVITIES
Property additions - gas distribution		(30,363	)		(27,494	)
Property additions - corporate and other		(230	)		(1,309	)
Business acquisition, net of cash acquired		-			(3,079	)
Property retirement costs, net of proceeds from property sales		(595	)		(388	)
Equity contribution to gas storage partnership		(1,930	)		-
Proceeds from redemption of investment in unconsolidated subsidiary		-			1,240
Changes in restricted cash		(2,047	)		(2	)
NET CASH USED FOR INVESTING ACTIVITIES		(35,165	)		(31,032	)
CASH FLOWS PROVIDED BY (USED FOR) FINANCING ACTIVITIES
Issuance of common stock, net of expenses		86			30,499
Issuance of convertible cumulative preferred stock, net of expenses		-			66,362
Repurchase of convertible cumulative preferred stock, net of expenses		(12,587	)		-
Repurchase of convertible preference stock and common stock warrants		-			(60,000	)
Repayment of notes payable and payment of related expenses		(46,400	)		(21,388	)
Repayment of long-term debt		(102	)		(41,354	)
Payment of dividends on convertible cumulative preferred stock		(2,221	)		(1,458	)
Change in book overdrafts included in current liabilities		36			(547	)
NET CASH USED FOR FINANCING ACTIVITIES		(61,188	)		(27,886	)
CASH AND CASH EQUIVALENTS
Net increase		(2,525	)		(321	)
Beginning of period		4,124			2,118
End of period	$	1,599		$	1,797
The accompanying condensed notes to the unaudited consolidated financial statements are an integral part of these statements.

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SEMCO ENERGY, INC.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Unaudited)
	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2006			2005			2006		2005
	(In thousands)
NET INCOME (LOSS)	$	(5,888	)	$	(7,392	)	$	3,274	$	2,991
Valuation adjustment for marketable securities, net of income tax (expense) benefit of $(18), $(20), $(33) and $(20)		33			24			60		37
Unrealized derivative gain on an interest rate hedge from an investment in an affiliate		-			35			28		98
COMPREHENSIVE INCOME (LOSS)	$	(5,855	)	$	(7,333	)	$	3,362	$	3,126
The accompanying condensed notes to the unaudited consolidated financial statements are an integral part of these statements.

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SEMCO ENERGY, INC.

CONDENSED NOTES TO THE UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

Note 1 - Significant Accounting Policies

SEMCO Energy, Inc. and its subsidiaries operate one reportable business segment: gas distribution. The Company’s gas distribution business segment distributes and transports natural gas to approximately 283,000 customers in Michigan and approximately 125,000 customers in Alaska. These operations are known together as the “Gas Distribution Business.” The Gas Distribution Business is subject to regulation by the Michigan Public Service Commission (“MPSC”) and the City Commission of Battle Creek (“CCBC”) in Michigan and the Regulatory Commission of Alaska (“RCA”) in Alaska.

The Company’s other business segments do not meet the quantitative thresholds required to be reportable business segments (“non-separately reportable business segments”) and are combined and included with the Company’s corporate division in a category the Company refers to as “Corporate and Other.” The Company’s non-separately reportable business segments primarily include operations and investments in information technology (“IT”) services, propane distribution, intrastate natural gas pipelines, and natural gas storage facilities. The Company’s corporate division is a cost center rather than a business segment.

References to the “Company” in this document mean SEMCO Energy, Inc., SEMCO Energy, Inc. and its subsidiaries, individual subsidiaries or divisions of SEMCO Energy, Inc. or the business segments discussed above as appropriate in the context of the disclosure.

Under the rules and regulations of the Securities and Exchange Commission (the “SEC”) for Quarterly Reports on Form 10-Q, certain footnotes and other financial statement information normally included in the year-end financial statements of the Company have been condensed or omitted in the accompanying unaudited financial statements. These financial statements prepared by the Company should be read in conjunction with the financial statements and notes thereto included in the Company's 2005 Annual Report on Form 10-K filed with the SEC. The information in the accompanying financial statements reflects, in the opinion of the Company's management, all adjustments (which include only normal recurring adjustments) necessary for a fair statement of the information shown, subject to year-end and other adjustments, as later information may require or warrant.

Use of Estimates - The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America (“GAAP”) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ materially from those estimates.

Discontinued Operations- The Company’s income from discontinued operations of $0.5 million for the three and nine months ended September 30, 2005, was from a settlement of litigation related to the Company’s discontinued construction services business, which was sold in 2004.

Goodwill and Goodwill Impairments - The Company accounts for goodwill under the provisions of Statement of Financial Accounting Standards (“SFAS”) 141, “Business Combinations,” and SFAS 142, “Goodwill and Other Intangible Assets.” Under these standards, the Company is required to perform impairment tests on its goodwill annually or at any time when events occur that could impact the value of the Company’s business segments or operations. 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 2006 annual goodwill impairment test for the Company’s propane operations was performed during the third quarter of 2006 and showed that there was no impairment of goodwill. The 2006 annual impairment tests for the Company’s Gas Distribution Business will be conducted during the fourth quarter of 2006. There were no changes in the carrying amount of goodwill for the nine-month period ended September 30, 2006.

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SEMCO ENERGY, INC.

CONDENSED NOTES TO THE UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

(Continued)

Note 1 - Significant Accounting Policies (Continued)

	Gas		Corporate
	Distribution		and		Total
	Segment		Other		Company
	(in thousands)
Goodwill as of December 31, 2005 and September 30, 2006	$	140,318	$	3,056	$	143,374

Share-Based Compensation - In December 2004, the Financial Accounting Standards Board (“FASB”) issued SFAS 123 (revised 2004) — “Share-Based Payment” (“SFAS 123-R”). This standard supersedes Accounting Principles Board Opinion No. 25, “Accounting for Stock Issued to Employees” (“APB 25”) and requires recognition of expense in the Company’s financial statements for the cost of share-based payment transactions, including stock option awards, based on the fair value of the award at the grant date. This standard also amends SFAS 95, “Statement of Cash Flows,” to require that excess tax benefits related to the excess of the share-based compensation deductible for tax purposes over the compensation recognized for financial reporting purposes be classified as cash inflows from financing activities rather than as a reduction of taxes paid in operating activities.

The Company adopted this standard on January 1, 2006, using the modified prospective method described in SFAS 123-R. Under this transition method, compensation expense recognized during the three and nine months ended September 30, 2006, included: (i) compensation expense for all share-based awards granted prior to, but not yet vested as of, December 31, 2005, based on the grant date fair value estimated in accordance with the provisions of SFAS 123, “Accounting for Stock-Based Compensation,” as amended by SFAS 148, “Accounting for Stock-Based Compensation — Transition and Disclosure” (collectively “SFAS 123”); and (ii) compensation expense for all share-based awards granted after December 31, 2005, based on the grant date fair value estimated in accordance with the provisions of SFAS 123-R. In accordance with the modified prospective method, results from prior periods have not been restated.

Prior to the adoption of SFAS 123-R, the Company accounted for share-based compensation arrangements in accordance with SFAS 123. In accordance with SFAS 123, the Company chose to account for certain of its share-based compensation arrangements under APB 25 for purposes of determining net income but presented the pro forma disclosures required by SFAS 123. As a result, the Company’s net income (loss) as reported in its Consolidated Statements of Operations for periods prior to January 1, 2006, reflected compensation expense for certain of its share-based compensation arrangements calculated using the intrinsic value method provided for under the provisions and related interpretations of APB 25 rather than the fair value method provided for under SFAS 123. If all of the Company’s share-based compensation expense for periods prior to January 1, 2006, had been determined in a manner consistent with the provisions of SFAS 123, the Company’s net income (loss) available to common shareholders and related earnings (loss) per share would have been reduced to the pro forma amounts set forth in the table below:

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SEMCO ENERGY, INC.

CONDENSED NOTES TO THE UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

(Continued)

Note 1 - Significant Accounting Policies (Continued)

	Three			Nine
	Months Ended			Months Ended
	September 30,			September 30,
	2005			2005
	(in thousands, except per share amounts)
Net income (loss) available to common shareholders
As reported	$	(8,339	)	$	(8,165	)
Add back share-based compensation expense included in reported net income, net of related tax effects		172			370
Deduct total share-based compensation expense determined under fair value based method for all awards, net of related tax effects		245			577
Pro forma	$	(8,412	)	$	(8,372	)
Earnings (loss) per share - basic
As reported	$	(0.27	)	$	(0.28	)
Pro forma	$	(0.27	)	$	(0.29	)
Earnings (loss) per share - diluted
As reported	$	(0.27	)	$	(0.28	)
Pro forma	$	(0.27	)	$	(0.29	)

As a result of adopting SFAS 123-R on January 1, 2006, the Company’s income before income taxes and net income available to common shareholders were $0.1 million lower for the three months ended September 30, 2006, and $0.4 million and $0.3 million lower, respectively, for the nine months ended September 30, 2006, than if the Company had continued to account for share-based compensation under APB 25. The reductions in earnings reduced basic and diluted earnings per share by $0.01 for the nine months ended September 30, 2006, but were insufficient to cause a change in basic and diluted earnings per share for the three months ended September 30, 2006. Refer to Note 4 for further information about the Company’s share-based compensation arrangements.

New Accounting Standards Not Yet Effective - In June 2006, the FASB issued Financial Interpretation Number (‘‘FIN’’) 48, ‘‘Accounting for Uncertainty in Income Taxes - an interpretation of SFAS No. 109.” This interpretation clarifies the accounting for uncertainty in income taxes recognized in a Company’s financial statements in accordance with SFAS 109, “Accounting for Income Taxes.” FIN 48 prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a position taken, or expected to be taken, in a tax return. FIN 48 also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition. The provisions of FIN 48 are effective for fiscal years beginning after December 15, 2006. The Company is currently evaluating the impact of FIN 48.

 

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SEMCO ENERGY, INC.

CONDENSED NOTES TO THE UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

(Continued)

Note 1 - Significant Accounting Policies (Continued)

In September 2006, the FASB issued SFAS 157, “Fair Value Measurements.” SFAS 157 defines fair value, provides guidance for using fair value to measure assets and liabilities and expands disclosures about fair value measurements. SFAS 157 applies to other standards that require (or permit) assets or liabilities to be measured at fair value but does not expand the use of fair value in any new circumstances. This statement is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. The Company is in the process of evaluating the effect of this statement on its consolidated financial position and results of operations.

In September 2006, the FASB issued SFAS 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans, an amendment of FASB Statements No. 87, 88, 106, and 132(R),” which changes the financial reporting for defined benefit pension and postretirement plans. SFAS 158 is effective as of December 31, 2006, and requires companies to, among other things, recognize in their consolidated statements of financial position the funded status of their defined benefit postretirement plans measured as the difference between the fair value of plan assets and the related benefit obligation. For a pension plan, the benefit obligation would be the projected benefit obligation; for any other postretirement benefit plan, such as a retiree health care plan, the benefit obligation would be the accumulated postretirement benefit obligation. SFAS 158 also requires companies to recognize as a component of other comprehensive income, net of tax, the actuarial gains and losses and the prior service costs and credits that arise during the period but, pursuant to SFAS 87 and 106, are not recognized as components of net periodic benefit cost in the consolidated statement of operations. Amounts recognized in accumulated other comprehensive income would be adjusted as they are subsequently recognized as components of net periodic benefit cost pursuant to the recognition and amortization provisions of SFAS 87 and 106.

The Company estimates that, if it had adopted SFAS 158 on September 30, 2006, its consolidated statement of financial position would have been affected as follows: (i) accrued pension and other postretirement benefit costs would have increased by an estimated $16.0 million to $17.0 million; (ii) common shareholders’ equity (specifically, accumulated comprehensive income) would have decreased by an estimated $10.0 million to $10.7 million; and (iii) the deferred income tax liability would have decreased by an estimated $6.0 million to $6.3 million. When the Company adopts SFAS 158 on December 31, 2006, the impact on its consolidated statements of financial position could differ substantially from what is described here, depending on various factors, including, the discount rate and fair value of current plan assets at December 31, 2006, and the amount of any contributions the Company may make to fund its pension and postretirement benefits plans on or before December 31, 2006.

The Company estimates that the adoption of SFAS 158 will not have a material impact on the Company’s consolidated statements of operations or cash flow. However, the Company’s consolidated statements of comprehensive income for periods after December 31, 2006, could be affected materially by the recognition of actuarial gains and losses and the prior service costs and credits that arise during the period but, pursuant to SFAS 87 and 106, are not recognized as components of net periodic benefit cost in the Company’s consolidated statement of operations. In addition, the Company has reached an agreement to modify its Bank Credit Agreement, as defined in Note 2 below, to exclude the impact on shareholders’ equity of adopting SFAS 158 from certain financial covenants.

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SEMCO ENERGY, INC.

CONDENSED NOTES TO THE UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

(Continued)

Note 2 - Short-Term Borrowings and Capitalization

Short-Term Borrowings - On October 13, 2006, the Company established an unsecured $15 million discretionary bank line of credit (“Line of Credit”) that expires on October 1, 2007. The bank is not obligated to make any advances under the Line of Credit and may at any time, without notice, in its sole and absolute discretion, refuse to make advances to the Company. Interest paid under the Line of Credit is at variable rates, which are based upon prime lending rates or rates quoted by the bank.

The Company has an unsecured $120 million revolving bank credit agreement, which expires on September 15, 2008 (the “Bank Credit Agreement”). Interest paid under the terms of the Bank Credit Agreement is at variable rates, which are based on LIBOR or prime lending rates, plus applicable margins. LIBOR-based borrowings are permitted for periods ranging from two weeks to one, two, three or six months. At September 30, 2006, the Company was utilizing $32.8 million of the borrowing capacity available under the Bank Credit Agreement, leaving approximately $87.2 million of the borrowing capacity unused. The $32.8 million of capacity being used consisted of $0.3 million of letters of credit and $32.5 million of borrowings. These amounts will change from time to time, reflecting the Company’s then current working capital needs.

Covenants in the Company’s Bank Credit Agreement require maintenance at the end of each calendar quarter of a minimum consolidated net worth of $225.0 million, adjusted annually by 50% of consolidated net income, if positive, plus 100% of the proceeds of each new capital offering conducted by the Company or any of its subsidiaries on or after June 30, 2005, net of issuance costs, less the aggregate principal amount of any junior capital which is retired, prepaid or redeemed in connection with a new capital offering. At September 30, 2006, the required minimum net worth was $225.0 million. In addition, the Bank Credit Agreement requires the Company to maintain, at the end of each fiscal quarter, a minimum interest coverage ratio of not less than 1.25 to 1 through September 30, 2007, and not less than 1.30 to 1 thereafter, and a maximum leverage ratio of not more than 65%. The Company’s failure to comply with any of its financial covenants may result in an event of default which, if not cured or waived, could result in the acceleration of the debt under the Bank Credit Agreement or the indentures governing its outstanding debt issuances that contain cross-acceleration or cross-default provisions. In such a case, there can be no assurance that the Company would be able to refinance or otherwise repay such indebtedness, which could result in a material adverse effect on its business, results of operation, liquidity and financial condition.

5% Series B Convertible Cumulative Preferred Stock - Holders of shares of the 5% Series Convertible Cumulative Preferred Stock (“Preferred Stock”) are entitled to receive cumulative annual cash dividends of $10 per share, payable quarterly in cash on each February 15, May 15, August 15 and November 15. Dividends are paid in arrears on the basis of a 360-day year consisting of twelve 30-day months. Dividends on the Preferred Stock accumulated from the date of issuance and compound quarterly. On August 15, 2006, the Company paid dividends on the 239,216 shares of Preferred Stock outstanding totaling approximately $0.6 million, or $2.50 per share. The Company’s Board of Directors also has declared a dividend on the Preferred Stock payable on November 15, 2006, at a rate of $2.50 per share, to holders of record on November 1, 2006. For further information on the Preferred Stock, refer to Note 4 of the Notes to the Consolidated Financial Statements in the Company’s 2005 Annual Report on Form 10-K.

In April and May of 2006, the Company repurchased and retired 50,884 and 59,900 shares, respectively, of Preferred Stock, such that there were 239,216 shares of Preferred Stock outstanding at September 30, 2006. For further information on these transactions, see the section below captioned “Common Shareholder’s Equity.”

- 13 -

SEMCO ENERGY, INC.

CONDENSED NOTES TO THE UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

(Continued)

Note 2 - Short-Term Borrowings and Capitalization (Continued)

Common Shareholder’s Equity -During the three and nine months ended September 30, 2006, the Company issued 8,232 shares and 27,529 shares, respectively, of its Common Stock to participants in the Company’s Direct Stock Purchase and Dividend Reinvestment Plan (“DRIP”) to meet DRIP Common Stock purchase requirements. Also during the three and nine months ended September 30, 2006, the Company issued 33,101 shares and 122,518 shares, respectively, of its Common Stock to certain of the Company's employee benefit plans.

During the second quarter of 2006, the Company issued 8,500 shares of Company Common Stock to members of the Company’s Board of Directors as part of the compensation for their services. These restricted shares of Common Stock vest over periods up to three years and their value at the time of issuance (less than $0.1 million) was added to the Company’s common shareholders equity. There is an offsetting amount that is also recorded in common shareholders equity representing the unearned compensation associated with all outstanding restricted Common Stock. For additional information on the restricted Common Stock, refer to Note 4.

On April 24, 2006, the Company issued 865,028 shares of the Company’s Common Stock and paid $5.0 million in cash to a holder of the Company’s Preferred Stock, in exchange for 50,884 shares of Preferred Stock, which were retired. On May 26, 2006, the Company issued 689,996 shares of the Company’s Common Stock and paid $7.6 million in cash to another holder of the Company’s Preferred Stock, in exchange for 59,900 shares of Preferred Stock, which were retired. These transactions resulted in a gain of $0.2 million, which is reflected in dividends on the Preferred Stock in the Company’s Consolidated Statement of Operations for the nine months ended September 30, 2006. The components of these transactions that do not involve the exchange of cash are not reflected in the Company’s Consolidated Statements of Cash Flows.

Note 3 - Risk Management Activities and Derivative Transactions

The Company’s business activities expose it to a variety of market risks, including commodity price risk and interest rate risk. The Company uses various risk management methods to monitor and address market risks. Derivative instruments are used to manage some market risks. The Company’s management identifies risks associated with the Company’s business and determines which risks it wants to manage with derivative instruments and which types of instruments it should use to manage those risks.

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

- 14 -

SEMCO ENERGY, INC.

CONDENSED NOTES TO THE UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

(Continued)

Note 3 - Risk Management Activities and Derivative Transactions (Continued)

An affiliate in which the Company has a 50% ownership interest (Eaton Rapids Gas Storage System or “ERGSS”) used a floating-to-fixed interest rate swap agreement to hedge the variable interest rate payments on a portion of its long-term debt. This swap was designated as a cash flow hedge under SFAS 133, and the difference between the amounts paid and received under the swap was recorded as an adjustment to ERGSS’s interest expense over the term of the agreement. In March 2006, the swap and related long-term debt matured and ERGSS repaid the debt. The Company’s share of changes in the fair value of the swap was recorded in accumulated comprehensive income during the term of the swap. The final adjustment to the Company’s equity investment in the affiliate and in accumulated comprehensive income, recorded in the first quarter of 2006, was an increase of less than $0.1 million.

The Company may, from time to time, enter into fixed-to-floating interest rate swaps in order to maintain its desired mix of fixed-rate and floating-rate debt. These swaps are designated as fair value hedges under SFAS 133, and the difference between the amounts paid and received under these swaps is recorded as an adjustment to interest expense over the term of the swap agreement. If the swaps are terminated, any unrealized gains or losses are recognized pro-rata over the remaining term of the hedged item as an increase or decrease in interest expense. The Company entered into one such interest rate swap in January 2004, in order to hedge one third of its $150 million of 7.125% notes due 2008. This agreement qualifies under the provisions of SFAS 133 as a fair value hedge. In accordance with SFAS 133, the Company’s Consolidated Statements of Financial Position at September 30, 2006, included a liability of $1.8 million and a decrease in long-term debt of $1.8 million for this interest rate swap.

Note 4 - Share-Based Compensation

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

The Company also has a deferred compensation plan for its Board of Directors and an employee stock gift program. The deferred compensation plan allows for the deferral of Director compensation, at the Director’s election, and deferred amounts can be invested in the Company’s Common Stock. Any deferral of Director compensation is expensed in the Company’s Consolidated Statement of Operations when earned by the Director. The employee stock gift program provides one free share of Company Common Stock to an employee the first time he or she enrolls in the Company’s program to make contributions to the Company’s DRIP via employee payroll deductions. The Board of Directors has decided to terminate the employee stock gift program, subject to satisfying any bargaining duty it may have with respect to such termination with the collective bargaining representatives of certain employee groups.

 

- 15 -

SEMCO ENERGY, INC.

CONDENSED NOTES TO THE UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

(Continued)

Note 4 - Share-Based Compensation (Continued)

At September 30, 2006, there were approximately 561,000 share-based awards available to be granted to employees and Directors under these plans. There were no modifications to awards outstanding under these plans during the nine-month periods ended September 30, 2006, and 2005. The Company recognized expense related to its share-based compensation arrangements of $0.5 million and $1.4 million during the three and nine months ended September 30, 2006, respectively, and $0.3 million and $0.6 million during the three and nine months ended September 30, 2005, respectively. The tax benefit recognized in income in relation to this compensation expense was $0.2 million and $0.5 million, during the three and nine months ended September 30, 2006, respectively, and was $0.1 million and $0.2 million during the three and nine months ended September 30, 2005, respectively. The Company did not capitalize any expense related to its share-based arrangements during the three and nine months ended September 30, 2006, and 2005.

Restricted Stock Units for Executives -During 2004 and 2005, the Company issued 114,728 restricted stock units (“RSUs”) to certain Company executives under the 2004 Plan. Each RSU is equivalent to one share of Company Common Stock. 10,000 of the RSUs issued in 2004 have been forfeited because the executive to whom the RSUs were issued is no longer employed by the Company. Of the RSUs issued in 2005, 14,728 vest in full on the three-year anniversary of issuance as long as the executive who received the RSUs remains employed on the vesting date. The remaining 90,000 outstanding RSUs vest at different dates over the period from issuance to March 31, 2007. Approximately 42% of these remaining 90,000 RSUs vested in full on approximately the one-year anniversary of issuance, with the fulfillment of the requirement that the executives who received the RSUs remained employed on the vesting date. Approximately 29% of these remaining 90,000 RSUs vested in 2006, with the fulfillment of the requirements that the executives who received the RSU’s remained employed on the vesting date and that certain performance goals be attained. The remaining 29% vest in 2007, subject to the attainment of certain performance targets and as long as the executives remain employed on the vesting dates. Notwithstanding these vesting conditions, the RSUs vest in their entirety upon consummation of a change in control of the Company, as defined in the Company’s severance agreements with its executives. Settlement of the vested RSUs will be made in shares of the Company’s Common Stock. The earliest any such settlements would occur is 2007.

A summary of information regarding non-vested RSUs as of September 30, 2006, and changes during the nine-month period then ended is presented below:

				Weigted
	Number			Average
	of			Grant Date
	RSUs			Fair Value
Non-vested at January 1, 2006		69,728		$	6.04
Granted		-
Earned and vested		(28,750	)		5.84
Unearned		-
Forfeited		-
Non-vested at September 30, 2006		40,978		$	6.18

- 16 -

SEMCO ENERGY, INC.

CONDENSED NOTES TO THE UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

(Continued)

Note 4 - Share-Based Compensation (Continued)

The grant date fair value of an RSU is equal to the price of the underlying share of the Company’s Common Stock on the grant date. During the nine months ended September 30, 2005, 17,228 RSUs were granted to executives with a weighted average grant date fair value of $6.66 per unit. No RSUs were granted to executives during the nine months ended September 30, 2006. During the nine months ended September 30, 2005, and September 30, 2006, 35,000 RSUs with a total fair value of $0.2 million and 28,750 RSUs with a total fair value of $0.2 million, respectively, were earned and vested but, under the terms of the RSUs, will not be paid out in shares of Common Stock until 2007. As of September 30, 2006, there was a total of 63,750 RSUs earned and vested. As of September 30, 2006, there was $0.1 million of total unrecognized compensation cost related to non-vested RSUs granted under the 2004 Plan. That cost is expected to be recognized over a weighted-average period of 1.2 years.

Employee Performance Share Units - The Company also grants performance share units (“PSUs”) to certain of its employees under the 2004 Plan. The Company grants a specific number of PSUs, which is referred to as the “Target Grant.” During the nine months ended September 30, 2006, and September 30, 2005, the Company granted 225,705 and 168,667 PSUs, respectively. Each PSU is equivalent to one share of Company Common Stock. Under the terms of the PSUs, the grantee can vest in PSUs equivalent to 25% to 150% of the Target Grant if actual performance results are within 25% to 150% of the target performance goals. Following a three-year performance period, a percentage of PSUs will vest if the individuals who received the PSUs are actively employed with the Company on the last day of the performance period and if the threshold level of performance is met or exceeded with respect to at least one of the established performance goals. Notwithstanding these vesting conditions, if an employee’s employment is terminated prior to the end of the vesting period after the consummation of a change in control of the Company, the employee will vest in a number of PSUs at the end of the performance period equivalent to the number of PSUs they would otherwise have vested in, pro-rated for the number of days they were employed during the performance period. Settlement of vested PSUs will be made in shares of the Company’s Common Stock. The earliest any such settlements would occur is 2008.

A summary of information regarding non-vested PSUs as of September 30, 2006, and changes during the nine-month period then ended is presented below:

				Weighted
	Number			Average
	of			Grant Date
	PSUs			Fair Value
Non-vested at January 1, 2006		168,667		$	6.15
Granted		225,705			5.39
Earned and vested		-			-
Unearned		-			-
Forfeited		(11,575	)		5.74
Non-vested at September 30, 2006		382,797		$	5.71

 

- 17 -

SEMCO ENERGY, INC.

CONDENSED NOTES TO THE UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

(Continued)

Note 4 - Share-Based Compensation (Continued)

The grant date fair value of a PSU is equal to the price of the underlying share of the Company’s Common Stock on the grant date. The weighted-average grant date fair value of PSUs granted was $5.39 per unit during the nine months ended September 30, 2006, and $6.15 per unit during the nine months ended September 30, 2005. There were no PSUs settled in shares of Common Stock during the nine months ended September 30, 2006, and 2005. As of September 30, 2006, there was $1.3 million of total unrecognized compensation cost related to non-vested PSUs granted under the 2004 Plan. That cost is expected to be recognized over a weighted-average period of 1.9 years.

Restricted Common Stock for Directors -The Company grants shares of restricted Common Stock to non-employee Directors under the 2004 Plan as part of the compensation paid to Directors. The restricted Common Stock vests over a three-year period as long as the individuals who received the restricted Common Stock continue to serve on the Board of Directors on the vesting dates. Notwithstanding these vesting conditions, the restricted Common Stock for Directors vests in its entirety upon consummation of a change in control of the Company, as defined in the 2004 Plan, and in certain other circumstances.

A summary of information regarding non-vested restricted Common Stock as of September 30, 2006, and changes during the nine-month period then ended is presented below:

	Number of			Weighted
	Restricted			Average
	Stock			Grant Date
	Shares			Fair Value
Non-vested at January 1, 2006		161,500		$	5.83
Granted		8,500			5.42
Vested		(57,000	)		5.77
Forfeited		-			-
Non-vested at September 30, 2006		113,000		$	5.83

The grant date fair value of a share of restricted Common Stock is equal to the price of a share of the Company’s Common Stock on the grant date. During the nine months ended September 30, 2006, and September 30, 2005, 8,500 shares and 168,750 shares, respectively, of restricted Common Stock were granted with a weighted average grant date fair value of $5.42 per share and $5.83 per share, respectively. During the nine months ended September 30, 2006, and September 30, 2005, 57,000 shares and 7,250 shares, respectively, of restricted Common Stock were vested. The total value of shares vested during the nine-month periods ended September 30, 2006, and September 30, 2005, were $0.3 million and less than $0.1 million, respectively. As of September 30, 2006, there was $0.6 million of total unrecognized compensation cost related to non-vested restricted Common Stock granted under the 2004 Plan. That cost is expected to be recognized over a weighted-average period of 1.3 years.

- 18 -

SEMCO ENERGY, INC.

CONDENSED NOTES TO THE UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

(Continued)

Note 4 - Share-Based Compensation (Continued)

Options to Purchase Common Stock-The exercise price of all stock options granted under the 2004 Plan is equal to the average of the high and low market price of the Company’s Common Stock on the option grant date. The options vest over the three-year period following the date of grant and expire ten years from the date of grant. Notwithstanding this three-year vesting condition, stock options vest in their entirety upon consummation of a change in control of the Company, as defined in the Company’s severance agreements with its executives and the 2004 Plan. Both the number of options granted and the exercise price are adjusted for any stock dividends and stock splits occurring during the life of the options. The fair values of the options were estimated at the grant date using a Black-Scholes option pricing model and the weighted average assumptions shown in the table below:

	Nine Months Ended
	September 30,
	2006			2005
Expected volatility		35.47	%		41.92	%
Expected dividend yield		0.00	%		0.00	%
Risk-free interest rate		4.70	%		3.95	%
Average expected term (years)		5			5

The expected volatility is based on the historical volatility of the Company’s Common Stock. The Company uses historical data and other factors to estimate option exercise and employee termination within the model. The expected term of options granted is derived from historical data and other factors and represents the period of time that options granted are expected to be outstanding. The risk free rate for periods within the contractual life of an option is based on the U.S. Treasury yield curve in effect at the date of grant.

A summary of information regarding options as of September 30, 2006, and changes during the nine-month period then ended is presented below:

						Weighted
	Number			Weighted		Average		Aggregate
	of			Average		Remaining		Instrinsic
	Stock			Exercise		Contractual		Value
	Options			Price		Term (years)		(in thousands)
Outstanding at January 1, 2006		1,159,359		$	8.38
Granted		192,372			5.39
Exercised		-			-
Forfeited or expired		(9,599	)		5.67
Outstanding at September 30, 2006		1,342,132		$	7.97		6.53	$	238
Exercisable at September 30, 2006		945,449		$	8.98		5.61	$	177

- 19 -

SEMCO ENERGY, INC.

CONDENSED NOTES TO THE UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

(Continued)

Note 4 - Share-Based Compensation (Continued)

The weighted-average grant date fair value of options granted during the nine months ended September 30, 2006, and 2005, was $2.11 and $2.59, respectively. During the nine months ended September 30, 2005, the total intrinsic value of options exercised and the total cash received and tax benefits realized from the exercise of options were immaterial. As of September 30, 2006, there was $0.7 million of total unrecognized compensation cost related to non-vested stock options granted under the 2004 Plan. That cost is expected to be recognized over a weighted-average period of 1.7 years.

For further information regarding the impact of the adoption of SFAS 123-R on share-based compensation, refer to the caption “Share-Based Compensation” in Note 1.

Note 5 - Earnings Per Share

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

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

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2006		2005		2006		2005
	(in thousands)
Potential dilutive impact on average common shares outstanding when calculating diluted earnings per share
Assumed conversion of convertible cumulative preferred stock		6,254		9,150		7,647		6,653
Assumed conversion of convertible preference stock		-		-		-		2,159
Assumed exercise of stock options		23		96		20		56
Assumed settlement of restricted stock units and performance share units		171		11		183		17
Assumed vesting of non-vested restricted stock		15		28		35		9
Potential income statement adjustments when calculating diluted earnings per share
Eliminate dividends on convertible cumulative preferred stock assumed converted	$	649	$	947	$	2,103	$	2,044
Eliminate dividends and repurchase premium on convertible preference stock assumed converted	$	-	$	-	$	-	$	9,112

- 20 -

SEMCO ENERGY, INC.

CONDENSED NOTES TO THE UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

(Continued)

Note 5 - Earnings Per Share (Continued)

The following table outlines the computations of basic and diluted EPS for the three and nine months ended September 30, 2006, and 2005. The potential adjustments indicated in the previous table are not included in the following computations of diluted EPS if their impact for a given period is antidilutive when compared to basic EPS for the period:

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2006			2005			2006			2005
	(in thousands, except per share amounts)
Average common shares outstanding
Issued		35,390			31,224			34,622			29,386
Adjustments to reconcile to average common shares outstanding for purposes of computing basic EPS:
Subtract non-vested restricted stock		(113	)		(161	)		(145	)		(56	)
Add shares issuable under fully vested restricted stock units		64			26			49			16
As adjusted - basic		35,341			31,089			34,526			29,346
Adjustments to reconcile to average common shares outstanding for purposes of computing diluted EPS:
Assumed conversion of convertible cumulative preferred stock		-			-			-			-
Assumed conversion of convertible preference stock		-			-			-			-
Assumed exercise of stock options		-			-			20			-
Assumed settlement of restricted stock units and performance share units		-			-			183			-
Assumed vesting of non-vested restricted stock		-			-			35			-
Diluted		35,341			31,089			34,764			29,346
Income (loss) from continuing operations
As reported	$	(5,888	)	$	(7,930	)	$	3,274		$	2,453
Adjustments to reconcile to income (loss) from continuing operations for purposes of computing basic EPS:
Subtract dividends on convertible cumulative preferred stock		(649	)		(947	)		(2,103	)		(2,044	)
Subtract dividends and repurchase premium on convertible preference stock		-			-			-			(9,112	)
As adjusted - basic	$	(6,537	)	$	(8,877	)	$	1,171		$	(8,703	)
Adjustments to reconcile to income (loss) from continuing operations for purposes of computing diluted EPS:
Eliminate dividends on convertible cumulative preferred stock assumed converted		-			-			-			-
Eliminate dividends and repurchase premium on convertible preference stock assumed converted		-			-			-			-
Diluted	$	(6,537	)	$	(8,877	)	$	1,171		$	(8,703	)
Earnings per share from income (loss) from continuing operations
Basic	$	(0.18	)	$	(0.29	)	$	0.03		$	(0.30	)
Diluted	$	(0.18	)	$	(0.29	)	$	0.03		$	(0.30	)
Income from discontinued operations
As reported - basic	$	-		$	538		$	-		$	538
Diluted	$	-		$	538		$	-		$	538
Earnings per share from income from discontinued operations
Basic	$	-		$	0.02		$	-		$	0.02
Diluted	$	-		$	0.02		$	-		$	0.02
Net income (loss) available to common shareholders
As reported - basic	$	(6,537	)	$	(8,339	)	$	1,171		$	(8,165	)
Adjustments to reconcile to net income available to common shareholders for purposes of computing diluted EPS:
Eliminate dividends on convertible cumulative preferred stock assumed converted		-			-			-			-
Eliminate dividends and repurchase premium on convertible preference stock assumed converted		-			-			-			-
Diluted	$	(6,537	)	$	(8,339	)	$	1,171		$	(8,165	)
Earnings per share from net income (loss) available to common shareholders
Basic	$	(0.18	)	$	(0.27	)	$	0.03		$	(0.28	)
Diluted	$	(0.18	)	$	(0.27	)	$	0.03		$	(0.28	)

- 21 -

SEMCO ENERGY, INC.

CONDENSED NOTES TO THE UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

(Continued)

Note 6 - Business Segments

The Company has one reportable business segment known as the Gas Distribution Business. Under SFAS 131, “Disclosure about Segments of an Enterprise and Related Information,” a business segment that does not exceed certain quantitative levels is not considered a reportable business segment. Instead, business segments that do not exceed the quantitative thresholds are combined and reported in a separate category with other business activities that do not meet the definition of a business segment. The Company refers to this other category as “Corporate and Other.” For a description of the Company’s Gas Distribution Business segment and a description of the Company’s non-separately reportable business segments included in Corporate and Other, refer to Note 1. For information regarding the determination of reportable business segments, refer to Note 11 of the Notes to the Consolidated Financial Statements in the Company’s 2005 Annual Report on Form 10-K.

The accounting policies of the Company’s business segments are the same as those described in Notes 1 and 11 of the Notes to the Consolidated Financial Statements in the Company’s 2005 Annual Report on Form 10-K, except that intercompany transactions have not been eliminated in determining individual segment results.

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

The following table provides business segment information as well as a reconciliation of the segment information to the applicable line in the Consolidated Financial Statements:

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2006			2005			2006			2005
	(in thousands)
Operating revenues
Gas distribution	$	62,394		$	60,992		$	426,822		$	378,523
Corporate and other		4,049			3,286			12,064			11,732
Reconciliation to consolidated financial statements
Intercompany eliminations (a)		(2,251	)		(1,968	)		(6,183	)		(5,752	)
Consolidated operating revenues	$	64,192		$	62,310		$	432,703		$	384,503
Operating income (loss)
Gas distribution	$	(931	)	$	(1,985	)	$	31,941		$	34,701
Corporate and other		1,067			251			1,792			851
Consolidated operating income	$	136		$	(1,734	)	$	33,733		$	35,552
Depreciation and amortization
Gas distribution	$	6,874		$	6,742		$	20,578		$	20,158
Corporate and other		327			352			990			1,061
Consolidated depreciation and amortization	$	7,201		$	7,094		$	21,568		$	21,219

(a) Includes the elimination of intercompany gas distribution revenue of $56 and $164, respectively, for the three and nine months ended September 30, 2006, and $53 and $156, respectively, for the three and nine months ended September 30, 2005. Includes the elimination of intercompany corporate and other revenue of $2,195 and $6,019, respectively, for the three and nine months ended September 30, 2006, and $1,915 and $5,596, respectively, for the three and nine months ended September 30, 2005.

- 22 -

SEMCO ENERGY, INC.

CONDENSED NOTES TO THE UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

(Continued)

Note 7 - Pension Plans and Other Postretirement Benefits

The following tables summarize the components of the Company’s net pension benefit and net other postretirement benefit costs:

	Pension Benefits
	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2006			2005			2006			2005
	(in thousands)
Components of net benefit cost
Service cost	$	979		$	731		$	2,939		$	2,192
Interest cost		1,290			1,225			3,871			3,674
Expected return on plan assets		(1,482	)		(1,359	)		(4,448	)		(4,076	)
Amortization of prior service cost		34			27			102			81
Amortization of net loss		726			624			2,176			1,873
Net benefit cost	$	1,547		$	1,248		$	4,640		$	3,744
		Other Postretirement Benefits
	Three Months Ended						Nine Months Ended
	September 30,						September 30,
		2006			2005			2006			2005
	(in thousands)
Components of net benefit cost
Service cost	$	146		$	117		$	437		$	350
Interest cost		487			465			1,462			1,396
Expected return on plan assets		(576	)		(540	)		(1,730	)		(1,622	)
Amortization of transition obligation		18			17			52			52
Amortization of prior service cost		(72	)		(72	)		(215	)		(215	)
Amortization of net loss		99			50			299			149
Amortization of regulatory asset		225			224			675			674
Net benefit cost	$	327		$	261		$	980		$	784

- 23 -

SEMCO ENERGY, INC.

CONDENSED NOTES TO THE UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

(Continued)

Note 8 - Commitments and Contingencies

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

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

The Company accrues for costs associated with environmental investigation and remediation obligations when such costs are probable and reasonably estimable. Accruals for estimated costs for environmental remediation obligations are generally recognized no later than the completion of the Company’s Remedial Action Plan (“RAP”) for a site. Such accruals are expected to be adjusted as further information becomes available or circumstances change. At three of the Company’s sites, the Company has begun efforts to determine the extent of remediation, if any, that must be performed, with the expectation of completing and submitting an RAP for each of the sites to the MDEQ. As a result of investigational work performed to date, the Company has recorded an accrual and a corresponding regulatory asset in the amount of $1.6 million for estimated environmental investigation and remediation costs that it believes are probable at these three sites. The Company has not discounted this accrual to its present value.

The accrual of $1.6 million represents what the Company believes is probable and reasonably estimable. However, the Company also believes that it is reasonably possible that there could be up to an estimated $18.5 million of environmental investigation and remediation costs for these three sites, in addition to the $1.6 million already accrued. It is also reasonably possible that the amount accrued or the reasonably possible range of costs may change in the future as the Company’s investigation of these sites continues and remediation activities are undertaken. The Company’s cost estimates have been developed using probabilistic modeling, advice from outside consultants, and judgment by management. The liabilities estimated by the Company are based on a current understanding of the costs of investigation and remediation. Actual costs, which may differ materially from these estimates, may vary depending, among other factors, on the environmental conditions at each site, the level of any remediation required, and changes in applicable environmental laws.

- 24 -

SEMCO ENERGY, INC.

CONDENSED NOTES TO THE UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

(Continued)

Note 8 - Commitments and Contingencies (Continued)

The Company has done less investigational and remediation work at the remaining four sites but has met all applicable MDEQ requirements. The Company believes that further investigation and any remediation of environmental conditions at these sites may be the obligation of other potentially responsible parties. It is reasonably possible that the Company’s current judgment concerning costs likely to be incurred in connection with the investigation and any remediation of conditions at these four sites may change in the future as new information becomes available and circumstances change, including the Company’s further evaluation of the obligations of other potentially responsible parties for these costs.

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

Personal Property Taxes- The Company has a number of property tax appeals pending with various local taxing jurisdictions in Michigan. Refer to Note 13 of the Notes to the Consolidated Financial Statements in the Company’s 2005 Annual Report on Form 10-K for information concerning these property tax appeals. During 2005, the Company made settlement offers to all taxing jurisdictions involved in the property tax appeals. Certain taxing jurisdictions have accepted the Company’s settlement offers. As a result of settlement offers accepted in 2006, the Company has reduced its property tax expense for the three-month and nine-month periods ended September 30, 2006, by approximately $0.5 million and $1.3 million, respectively.

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

- 25 -

SEMCO ENERGY, INC.

CONDENSED NOTES TO THE UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

(Continued)

Note 8 - Commitments and Contingencies (Continued)

To mitigate its damages, the Company paid the Farmington Hills lease costs and marketed the space to prospective subtenants, since the time Acheson ceased making the lease payments. In March 2006, the Company entered into a sublease with a subtenant that will pay a portion of these lease costs. As a result of this sublease agreement, the Company recorded a $1.2 million pre-tax loss in the first quarter of 2006 representing the difference between the present value of the amount it expects to receive from the subtenant and the present value of the remaining amount owed to the landlord under the terms of the lease.

Aurora Gas LLC (“Aurora”) gave the Company notice of the suspension of gas deliveries, and subsequently suspended deliveries, to the Company’s Alaska Pipeline Company subsidiary (which, in turn, are delivered to the Company’s ENSTAR Division for resale to its customers in Alaska) under the gas supply contract between the Company and Aurora pursuant to which Aurora sells natural gas to the Company from the Moquawkie natural gas field (the “Moquawkie Contract”). Aurora asserted that it was permitted to take these actions because production has become “Not Economic,” as that term is defined in the Moquawkie Contract. The Company disagrees with Aurora’s contentions, and attempts to resolve this matter informally were unsuccessful. The Company has filed suit against Aurora and an affiliate in Alaska state court asserting, among other things, a breach of contract claim. Aurora has defended against the Company’s claims in this lawsuit by insisting upon its right to suspend gas deliveries. For further information concerning this dispute with Aurora and related rate recovery implications, refer to Note 9 - Regulatory Matters.

Note 9 - Regulatory Matters

MPSC Base Rate Filing - On May 25, 2006, the Company filed a request with the MPSC seeking authority to increase the Company’s MPSC Division base rates for service by approximately $18.9 million, in total. The Company’s request covers approximately 244,000 MPSC Division residential, commercial, and industrial customers.

As part of its filing, the Company also has proposed to change various aspects of the Company’s rate design (meaning the way in which the costs of providing service to customers are collected in base rates and other rates and charges). These proposed rate design changes include: (i) elimination of a consumption-based distribution charge for residential customers, to be replaced by a fixed monthly service charge (which would include the current fixed monthly customer charge) for those customers or, in the alternative, to collect a fixed monthly customer charge and a fixed distribution charge; (ii) collection of lost and unaccounted for (“LAUF”) gas costs in the gas cost recovery (“GCR”) rate or, in the alternative, an annual “true-up” of LAUF gas costs allowed by the MPSC in base rates and the Company’s actual LAUF gas costs; (iii) an annual “true-up” of the uncollectible (or bad debt) expense allowed by the MPSC in base rates and the Company’s actual uncollectible expense; (iv) the recovery of certain Company-sponsored or -funded conservation program costs; and (v) the recovery of the capital-related costs associated with the replacement of certain bare steel mains and storage field compressors.

The Company’s proposed base rates and rate design proposals are subject to review and approval by the MPSC. This process may include discussion of these proposals in detail, with the MPSC staff and others, with a view towards resolving the case by settlement, and one or more public evidentiary hearings. New base rates, if any, and the rate design ultimately approved by the MPSC may differ materially from what has been proposed by the Company in this filing. In addition, there are relationships between the Company’s proposed base rate increase and its rate design proposals, such that new base rates will be directly affected by the MPSC’s rate design decisions as well as by other factors influencing the costs of providing service to customers (including the then-current market price of natural gas).

- 26 -

SEMCO ENERGY, INC.

CONDENSED NOTES TO THE UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

(Continued)

Note 9 - Regulatory Matters (Continued)

In July 2006, the MPSC set a schedule for the proceeding on this filing and, based on that schedule, the Company expects the MPSC to decide the case by mid- to late-Spring 2007. The Company is unable to predict, however, either when the MPSC will act on the Company’s filing or the outcome of the MPSC proceeding.

CCBC Jurisdictional Filing - In May 2006, the Company and the CCBC filed a joint application with the MPSC requesting that the MPSC assume jurisdiction over the service area currently regulated by the CCBC. The joint application asked the MPSC to approve the CCBC tariff, rates, charges and conditions of service that are currently in effect. The Company and the CCBC recently submitted an amended joint application to address certain rate and procedural issues. In July 2006, the MPSC set a schedule for the proceeding on this filing and, based on that schedule, the Company expects a decision from the MPSC by the end of 2006 or early-2007. The Company is unable to predict, however, when the MPSC will act on this filing or what the outcome might be.

Aurora Gas Supply Contract - On or about April 1, 2006, the Company received a letter from Aurora regarding the Moquawkie Contract. In that letter, Aurora asserted that, after April 1, 2006, continued production of gas by Aurora for the Company would be “Not Economic” as that term is defined in the Moquawkie Contract, permitting Aurora to suspend deliveries to the Company effective October 1, 2006.

The Moquawkie Contract provides that Aurora will supply a portion of the Company’s gas requirements for ENSTAR through 2014. Aurora is required to deliver up to 1.8 Bcf of gas in 2006. This requirement declines annually until the projected final year requirement of 0.2 Bcf in 2014. The total remaining commitment at the end of 2005 was approximately 10 Bcf.

On October 1, 2006, Aurora suspended deliveries of gas to the Company under the Moquawkie Contract. The Company has obtained substitute gas from alternative sources. The cost of such gas is higher than the cost of gas under the Moquawkie Contract. The Company has filed with the RCA to recover from its customers the higher cost of the substitute gas. The Company also has told the RCA that if the Company recovers damages from Aurora, the Company intends to credit any recovery, net of the Company’s costs, against the gas costs borne by its Alaska customers.

Marathon Gas Supply Contract - In 2005, the Company entered into a gas supply contract with Marathon Oil Company (“Marathon”) to supply a portion of the needs of the Company’s Alaska customers from 2009 through 2017. In November 2005, the Company submitted the gas supply contract to the RCA for its approval and hearings began in July 2006. On September 28, 2006, having then concluded evidentiary hearings, the RCA rejected the gas supply contract negotiated between the Company and Marathon, holding, among other things, that the Company had not met its burden of demonstrating that gas supplies to be provided under the contract were reliable and that the contract price (which was proposed to be tied to an index) was reasonable. Parties to the case, including the Company, have filed motions for reconsideration and/or clarification of this RCA order. The Company is unable to predict whether the RCA will change or clarify its order or whether this gas supply contract (as submitted or with amendments that are acceptable to Marathon) will be approved or rejected by the RCA, including when the RCA might act.

- 27 -

SEMCO ENERGY, INC.

CONDENSED NOTES TO THE UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

(Continued)

Note 10 - Subsequent Events

On October 13, 2006, the Company established an unsecured $15 million discretionary bank Line of Credit that expires on October 1, 2007. For information on this new Line of Credit, refer to Note 2.

On October 31, 2006, the Company entered into a bank term loan agreement in the amount of $55 million. The term loan matures on June 30, 2016, and is callable at any time at the option of the Company. Interest on the loan is payable at variable rates based on LIBOR plus an applicable margin. The Company expects to receive the proceeds of the loan on or about November 29, 2006. The proceeds will be used to retire a portion of the $59.5 million principal amount outstanding of the Company’s 8% Series Notes due 2016. On November 1, 2006, the Company called for redemption of the $59.5 million of 8% Senior Notes due 2016, at a redemption price equal to 100% of the principal amount plus accrued interest. The notes will be redeemed on November 30, 2006.

- 28 -

PART I - FINANCIAL INFORMATION - (Continued)

Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations.

Summary of Results of Operations

The discussions in this section are summarized and intended to provide an overview of the results of Company operations. In most instances, the items discussed in this summary are covered in greater detail in later sections of Management’s Discussion and Analysis. Any variances in results in this section are quantified on an after-tax basis. The Company uses an effective income tax rate of 36.9% to estimate these after-tax amounts. All references to 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 5 of the Condensed Notes to the Unaudited Consolidated Financial Statements in Part 1, Item 1 of this Form 10-Q. The following table summarizes the Company’s operating results for the three and nine months ended September 30, 2006, and September 30, 2005:

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2006			2005			2006			2005
	(in thousands, except per share amounts)
Operating revenues	$	64,192		$	62,310		$	432,703		$	384,503
Operating expenses		64,056			64,044			398,970			348,951
Operating income (loss)	$	136		$	(1,734	)	$	33,733		$	35,552
Other income (deductions)		(9,606	)		(10,946	)		(28,973	)		(32,100	)
Income tax (expense) benefit		3,582			4,750			(1,486	)		(999	)
Income (loss) from continuing operations	$	(5,888	)	$	(7,930	)	$	3,274		$	2,453
Income from discontinued operations, net of income taxes		-			538			-			538
Net income (loss)	$	(5,888	)	$	(7,392	)	$	3,274		$	2,991
Dividends on convertible cumulative preferred stock		649			947			2,103			2,044
Dividends and repurchase premium on convertible preference stock		-			-			-			9,112
Net income (loss) available to common shareholders	$	(6,537	)	$	(8,339	)	$	1,171		$	(8,165	)
Earnings (loss) per share - basic
Income (loss) from continuing operations	$	(0.18	)	$	(0.29	)	$	0.03		$	(0.30	)
Net income (loss) available to common shareholders	$	(0.18	)	$	(0.27	)	$	0.03		$	(0.28	)
Earnings (loss) per share - diluted
Income (loss) from continuing operations	$	(0.18	)	$	(0.29	)	$	0.03		$	(0.30	)
Net income (loss) available to common shareholders	$	(0.18	)	$	(0.27	)	$	0.03		$	(0.28	)
Average common shares outstanding
Basic		35,341			31,089			34,526			29,346
Diluted		35,341			31,089			34,764			29,346

- 29 -

PART I - FINANCIAL INFORMATION - (Continued)

Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations (Continued).

Summary of Results of Operations (Continued)

Comparison of third quarter 2006 and third quarter 2005 results - The Company had a net loss available to common shareholders of $6.5 million (or $0.18 per share) for the three months ended September 30, 2006, compared to a net loss of $8.3 million (or $0.27 per share) for the three months ended September 30, 2005. The Company typically experiences losses in the non-heating season of each year, because, while the Company continues to incur expenses, revenue collections from customers are lower than in the higher usage heating season. The primary factors that contributed to the decrease in the net loss available to common shareholders for the third quarter of 2006 were: (i) an increase in gas distribution margin; (ii) a decrease in financing-related costs; (iii) a decrease in property tax expense; and (iv) the reversal, during the third quarter of 2006, of a second quarter 2006 write down of natural gas inventory due to changes in market factors. The impact of these items was partially offset by the inclusion in 2005 results of $0.5 million of income from discontinued operations.

The increase in gas distribution margin, which decreased the third quarter 2006 net loss by approximately $0.5 million, was primarily due to an increase in the volume of gas sold due to the impact of colder temperatures and new customers partially offset by conservation by customers. The decrease in financing-related costs decreased the third quarter of 2006 net loss by approximately $1.3 million, when compared to the third quarter of 2005. The decrease in property tax expense, which decreased the net loss for the third quarter of 2006 by approximately $0.3 million, was primarily the result of taxing jurisdictions in Michigan accepting the Company’s settlement offers related to outstanding property tax appeals. The adjustment in value of natural gas inventory decreased the 2006 net loss by approximately $0.3 million.

Comparison of nine months ended September 30, 2006, and nine months ended September 30, 2005, results - The Company’s net income available to common shareholders was $1.2 million (or $0.03 per share) for the nine months ended September 30, 2006, compared to a net loss of $8.2 million (or $0.28 per share) for the nine months ended September 30, 2005. The primary factors that contributed to the increase in net income available to common shareholders when comparing the results for the nine months ended September 30, 2006, to the results for the nine months ended September 30, 2005, included: (i) a decrease in financing-related costs; and (ii) a decrease in property tax expense, partially offset by the impact of (a) a decrease in gas distribution margin, (b) an increase in operations and maintenance expenses, and (c) the $0.5 million of income from discontinued operations reflected in 2005 results.

The decrease in financing-related costs increased net income for the nine months ended September 30, 2006, by approximately $11.0 million when compared to the nine months ended September 30, 2005. Two charges included in the results for the nine months ended September 30, 2005, were significant contributors to the decrease in financing-related costs in 2006. These charges were $0.9 million of debt extinguishment costs and a payment of approximately $8.2 million, which was associated with the repurchase of Convertible Preference Stock (“CPS”) and certain Common Stock warrants (“Warrants”) in March 2005. In addition, lower average levels of outstanding debt and preferred securities during the nine months ended September 30, 2006, when compared to the same period of 2005, also contributed to the decrease in financing related costs. The decrease in property tax expense, which increased net income by approximately $1.1 million, when comparing results for the first nine months of 2006 to the same period of 2005, was primarily the result of taxing jurisdictions in Michigan accepting the Company’s settlement offers related to outstanding property tax appeals.

- 30 -

 PART I - FINANCIAL INFORMATION - (Continued)

Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations (Continued).

Summary of Results of Operations (Continued)

The decrease in gas distribution margin decreased net income for the nine months ended September 30, 2006, by approximately $0.1 million when compared to the nine months ended September 30, 2005. Gas distribution margin decreased despite the positive impact of base rate increases in Michigan that became effective in April of 2005 and the addition of new customers in both Michigan and Alaska. The primary factors that decreased gas sales margin were: (i) a decrease in volumes of gas sold due to warmer weather, energy efficiency improvements, and energy conservation by customers; (ii) an increase in LAUF gas expense; and (iii) the inclusion in 2005 results of margins from the sale of excess gas by the Company’s Gas Distribution Business to a third-party gas supplier in 2005 and the absence of a similar sale in 2006. The increase in operations and maintenance expense decreased net income by approximately $1.8 million during the nine months ended September 30, 2006, when compared to the nine months ended September 30, 2005. This increase was due primarily to increases in employee benefit costs and uncollectible customer accounts and a charge incurred in connection with a sublease entered into during the first quarter of 2006.

The Impact of Higher Natural Gas Prices

The market price of natural gas increased substantially during the second half of 2005. The Company believes this increase was caused, in large part, by the impact of Hurricanes Katrina and Rita on drilling, production, pipelines and processing facilities in and around the Gulf of Mexico, along with the supporting infrastructure and resources for those facilities. Since mid-December 2005, natural gas prices have receded from the higher levels established during the second half of 2005. This decline in prices may be attributable, among other factors, to reduced customer gas consumption in reaction to high prices, relatively warm weather during the first quarter of 2006 throughout the midwestern and eastern portions of the United States, and relatively high levels of working gas in storage during much of 2006 in comparison to average levels over the last five years. Despite the recent decrease in the market price of natural gas and lower-than-expected projected prices for the 2006-2007 winter heating season, as compared to the prior year, future prices still remain relatively high beyond the winter heating season and relative to average prices over the last five years. The Company believes that higher natural gas prices are likely in the future, and such higher prices will persist and that gas prices will remain volatile due to a variety of factors, including an apparent imbalance between natural gas supplies and demand resulting from, among other things, the use of substantial amounts of natural gas to generate electricity and environmental and other restrictions on natural gas exploration and production.

When gas prices are volatile and increase substantially (such as occurred in the second half of 2005), the Company may require approval in certain of its regulatory jurisdictions to increase the commodity, or GCR, component of rates, to ensure the timely recovery of the cost of gas purchased for sale to customers. In addition, higher gas costs may decrease customer consumption, increase delinquent or uncollectible accounts, and increase the value of LAUF natural gas volumes. These and other factors could result in an increase in working capital requirements and the need for the Company to borrow additional amounts under its Bank Credit Agreement or one or more lines of credit, if available.

 

- 31 -

PART I - FINANCIAL INFORMATION - (Continued)

Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations (Continued).

The Impact of Higher Natural Gas Prices (Continued)

The Company has been addressing, and continues to address, the impact of higher and more volatile natural gas prices by (i) seeking GCR rate increases in Michigan to recover the cost of gas on a timely basis, (ii) monitoring working capital requirements, (iii) evaluating customer consumption, and (iv) monitoring customer payment patterns. In addition, in May 2006, the Company filed a request with the MPSC seeking authority to increase the base rates the Company charges to customers in its service areas regulated by the MPSC. As part of this filing, the Company also has proposed to change various aspects of the Company’s rate design in order to address, among other things, the impact of higher and more volatile natural gas prices. The Company expects the MPSC to decide the case by mid- to late-Spring 2007. The Company is unable to predict, however, either when the MPSC will act on the Company’s filing or the outcome of the MPSC proceeding. Refer to Note 9 of the Condensed Notes to the Unaudited Consolidated Financial Statements in Part 1, Item 1 of this Form 10-Q for information regarding the proposed increase in base rates and rate design proposals.

During the past 12 months,the Company has been successful in obtaining GCR rate increases on a timely basis to recover higher gas costs. Timely GCR rate changes have helped reduce the Company’s working capital requirements by eliminating the need to finance for an extended period any under-recovery of gas costs not recouped in current GCR rates. Higher gas costs have increased the Company’s need for additional working capital for other purposes, however, such as to finance gas purchases at higher market prices, finance storage inventory, and carry accounts receivable. The recent decline in natural gas prices has reduced the Company’s working capital requirements. However, working capital requirements would likely increase if natural gas prices increased again in the future. Refer to the section of Management’s Discussion and Analysis titled “Future Financing Plans” for additional information regarding the utilization of the Company’s Bank Credit Agreement and lines of credit and the higher level of short-term borrowings being experienced by the Company.

The Company believes that higher gas costs, to the extent they are reflected in GCR rates, have affected, and will continue to affect, gas consumption by customers, who are induced by higher prices to conserve. Despite the recent decrease in the market price of natural gas from the highs established in the second half of 2005, prices for natural gas are still higher than they were a few years ago. In addition, the GCR portion of customer rates in Alaska is expected to increase substantially on January 1, 2007, as a result of increases in prices under the Company’s RCA-approved long-term gas supply contracts, which provide for annual adjustments to the price the Company pays for gas based on, among other things, the price (during specific trailing periods) of certain traded natural gas and oil futures contracts. Based on these and other factors (including the possibility of future price increases), the Company is unable to estimate, with certainty, the amount of future conservation (if any) that is likely to occur. Based on normalized 2005 consumption, however, the Company estimates that every one percent decrease in customer consumption in Michigan may cause decreases in 2006 gas sales margin of approximately (i) $0.2 million to $0.3 million for the first quarter, (ii) less than $0.1 million for the second quarter and the third quarter, (iii) $0.1 million to $0.2 million for the fourth quarter, and (iv) $0.5 million to $0.6 million for the year. Based on normalized 2005 consumption, the Company estimates that every one percent decrease in customer consumption in Alaska may cause decreases in 2006 gas sales margin of approximately (i) $0.1 million to $0.2 million for the first quarter, (ii) less than $0.1 million for the second quarter and the third quarter, (iii) $0.1 million to $0.2 million for the fourth quarter, and (iv) $0.3 million to $0.4 million for the year. Refer to the section in Management’s Discussion and Analysis titled “The Impact of Weather and Energy Conservation” for customer consumption information for the nine months ended September 30, 2006, and 2005.

- 32 -

PART I - FINANCIAL INFORMATION - (Continued)

Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations (Continued).

The Impact of Higher Natural Gas Prices (Continued)

Higher gas costs, to the extent they are reflected in GCR rates, may also affect the ability of some customers to pay their bills for gas service on time or in full. The Company is, and has been, monitoring customer payment patterns and encouraging customers to elect budget-type levelized payment plans in order to spread winter heating season bills over a 12-month period. In addition to disconnecting service to delinquent customers, as necessary and permitted, the Company refers customers to sources of charitable and public assistance. The Company also participates in efforts to secure charitable donations that will provide such assistance.

The Company’s expense for uncollectible gas sales customer accounts as a percent of gas sales revenue was 0.42% for 2005, 0.43% for 2004 and 0.50% for 2003. Assuming that future expense for uncollectible accounts as a percent of annual gas sales revenue is similar to the experience in 2005, for each 10% increase in annual gas sales revenue (principally driven by the change in natural gas prices), there would be an expected increase in annual expense for uncollectible accounts of approximately $0.2 million. The Company’s expense for uncollectible gas sales customer accounts was $2.9 million and $2.0 million for the nine months ended September 30, 2006, and 2005, respectively. The $0.9 million increase in expense for uncollectible gas sales customer accounts for the nine months ended September 30, 2006, when compared to the same period ended September 30, 2005, was primarily attributable to higher gas prices (resulting in higher customer bills), reduced government funding of low income heating programs and rules limiting the ability of the Gas Distribution Business to terminate service to delinquent customers. The Company’s expense for uncollectible gas sales customer accounts as a percent of gas sales revenue for the trailing 12 months was 0.54% at September 30, 2006, compared to 0.45% at September 30, 2005. The Company cannot provide any assurance that its future expense for uncollectible accounts will be consistent with its prior experience, in view of the various factors affecting customer payment patterns (including regulations governing service disconnections).

The Company also expects that higher gas costs will increase the expense associated with LAUF gas in its Michigan service areas, assuming that LAUF volumes are consistent with LAUF volumes in prior periods. Annual LAUF volumes in Michigan have ranged from 0.5% to 1.4% of volumes sold and transported in the Company’s Michigan service area over the last ten years. The Company’s Michigan gas distribution operation typically accounts for 48% to 57% of total volumes sold and transported by the Company. LAUF gas volumes in Michigan for the nine months ended September 30, 2006, and 2005, were approximately 260 MMcf and 274 MMcf, respectively, or 0.7% and 0.7%, respectively, of volumes sold and transported in Michigan. The expense associated with LAUF gas in Michigan was $2.4 million and $1.9 million for the nine months ended September 30, 2006, and 2005, respectively.

The Impact of Weather and Energy Conservation

Temperature fluctuations and energy conservation have a significant impact on operating results of the Company. Accordingly, the Company believes that information about normal temperatures and consumption is useful for understanding its business and operating results.

Consumption of natural gas for heating is largely determined by weather, and a portion of the Company’s revenues is collected through consumption-based charges. The Company’s budgets, forecasts and business plans are prepared using expected gas consumption under normal weather conditions and historical consumption patterns. The regulatory bodies that have jurisdiction over the rates charged by the Gas Distribution Business use weather-normalized consumption data to set customer rates and to establish authorized rates of return.

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PART I - FINANCIAL INFORMATION - (Continued)

Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations (Continued).

The Impact of Weather and Energy Conservation(Continued)

Many of the Company’s customers appear to be continuing a pattern of conserving energy by utilizing energy-efficient heating systems, insulation, alternative energy sources, and other energy-saving devices and techniques. During the past several years, average annual per customer gas consumption has been decreasing. In addition, increases in natural gas prices appear to have increased conservation efforts by customers, prompting them to “dial down” their thermostats. While the market price of natural gas has decreased recently from the highs established during the second half of 2005, the Company expects this conservation trend to continue. The Company also believes that this apparent pattern of conserving energy is affected by underlying economic conditions in the Company’s service territories in Michigan. In addition, despite the recent decrease in the market price of natural gas from the highs established during the second half of 2005, the price the Company pays for gas for its customers in Alaska is expected to increase substantially on January 1, 2007, as a result of the pricing terms in its RCA-approved long-term gas supply contracts, as discussed above.

- 34 -

PART I - FINANCIAL INFORMATION - (Continued)

Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations (Continued).

The Impact of Weather and Energy Conservation(Continued)

The following table provides temperature and customer consumption data for the nine-month periods ended September 30, 2006, and September 30, 2005:

	Nine Months Ended
	September 30,
	2006			2005
Michigan
Degree days (DD) (a)
Actual		3,858			4,334
Normal (b)		4,404			4,379
Actual DD as a percent of normal DD		87.6	%		99.0	%
Percent by which actual DD differ from:
Normal DD (c)		(12.4	)%		(1.0	)%
Prior year actual DD (d)		(11.0	)%		(2.0	)%
Average gas consumption per customer (Mcf) (e)
Residential gas sales customers		60.1			71.3
Residential gas sales customers normalized (f)		68.6			72.0
Percent by which residential gas sales customers normalized differs from prior year residential gas sales customers normalized (g)		(4.8	)%		(2.4	)%
All gas sales customers		85.0			100.3
All gas sales customers normalized (f)		97.0			101.4
Percent by which all gas sales customers normalized differs from prior year all gas sales customers normalized (g)		(4.3	)%		(3.4	)%
Alaska
Degree days (DD) (a)
Actual		6,841			6,051
Normal (b)		6,387			6,478
Actual DD as a percent of normal DD		107.1	%		93.4	%
Percent by which actual DD differ from:
Normal DD (c)		7.1	%		(6.6	)%
Prior year actual DD (d)		13.1	%		(4.1	)%
Average gas consumption per customer (Mcf) (e)
Residential gas sales customers		118.3			106.4
Residential gas sales customers normalized (f)		110.5			113.9
Percent by which residential gas sales customers normalized differs from prior year residential gas sales customers normalized (g)		(3.0	)%		(5.2	)%
All gas sales customers		140.4			127.0
All gas sales customers normalized (f)		131.1			136.0
Percent by which all gas sales customers normalized differs from prior year all gas sales customers normalized (g)		(3.6	)%		(5.9	)%

(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 the period.

(b) Normal degree days for a particular period is the average of degree days during the prior 15 years. Beginning in 2006, normal degree days for the Company’s Alaska operations is determined using a 10-year average of degree days rather than a 15-year average.

(c) The percent by which actual degree days differ from normal degree days is often referred to as the percent by which temperatures were colder (warmer) than normal.

(d) The percent by which actual degree days differ from prior period actual degree days is often referred to as the percent by which temperatures were colder (warmer) than the prior period.

(e) Mcf is a quantity of natural gas equal to 1,000 standard cubic feet.

(f) Normalized average gas consumption is determined by dividing the actual average gas consumption by actual degree days as a percent of normal degree days. The normalized average gas consumption represents an estimate of what average gas consumption would have been if during the period in question, actual degree days had equaled normal degree days.

(g) The percent by which normalized average gas consumption differs from prior period normalized average gas consumption represents an estimate of the percentage change in gas consumption from one period to the next caused by factors other than temperature variations. This change can relate to various factors but is likely due to changes in energy conservation by customers.

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PART I - FINANCIAL INFORMATION - (Continued)

Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations (Continued).

The Impact of Weather and Energy Conservation(Continued)

The Company has estimated that, in its Michigan service area, temperatures were approximately 12.4% warmer than normal during the nine months ended September 30, 2006, and approximately 1.0% warmer than normal during the nine months ended September 30, 2005. In the Company’s Alaska service area, temperatures are estimated to have been approximately 7.1% colder than normal during the nine months ended September 30, 2006, and approximately 6.6% warmer than normal during the nine months ended September 30, 2005.

The Company has estimated that, in its Michigan service area, normalized average gas consumption during the nine months ended September 30, 2006, for all gas sales customers decreased by approximately 4.3%, when compared to the nine months ended September 30, 2005. In the Company’s Alaska service area, normalized average gas consumption during the nine months ended September 30, 2006, for all gas sales customers decreased by an estimated 3.6%, when compared to the nine months ended September 30, 2005.

The Company estimates that the combined variations from normal temperatures and decreases in normalized gas consumption decreased net income by approximately $2.9 million during the nine months ended September 30, 2006, and approximately $2.5 million during the nine months ended September 30, 2005.

Business Segment Overview

The Company has one reportable business segment known as the Gas Distribution Business. The Company’s other business segments do not meet the quantitative thresholds required to be reportable business segments and are combined and reported in a separate category with other business activities that do not meet the definition of a business segment. The Company refers to this separate category as “Corporate and Other.” For a description of the Company’s Gas Distribution Business and a description of the non-separately reportable business segments included in Corporate and Other, refer to Note 1 of the Condensed Notes to the Unaudited Consolidated Financial Statements in Part 1, Item 1 of this Form 10-Q.  For a summary of operating revenues and operating income by business segment, refer to Note 6 of the Condensed Notes to the Unaudited Consolidated Financial Statements in Part 1, Item 1 of this Form 10-Q.

The Gas Distribution Business segment analysis and other discussions below provide additional information regarding variations in operating results when comparing the three- and nine-month periods ended September 30, 2006, to the same periods of the prior year. 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 business segment discussion.

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PART I - FINANCIAL INFORMATION - (Continued)

Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations (Continued).

Gas Distribution Business Segment

The Company’s Gas Distribution Business consists of 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.”

Seasonality - The Company's Gas Distribution Business is seasonal with the majority of its operating revenue realized during the winter heating season each year. As a result, a substantial portion of the Company's annual income is earned during the first and fourth quarters of the year. Therefore, the Company's results of operations for the three and nine months ended September 30, 2006, and 2005, are not necessarily indicative of results for a full year.

Gas Sales Revenue - The Company’s gas sales revenue was $55.3 million and $398.9 million for the three and nine months ended September 30, 2006, compared to $54.0 million and $351.6 for the three and nine months ended September 30, 2005. The most significant factor causing the change in gas sales revenue from period to period is the change in the cost of gas sold. A significant portion of the Company’s cost of gas sold is accounted for by the Company’s GCR pricing mechanisms, which allow for the adjustment of rates charged to customers to reflect increases and decreases in the cost of gas purchased by the Company. Under these mechanisms, customers are charged rates that allow the Company to recoup its cost of gas purchased for sale to customers, subject, in the Company’s Michigan service territory regulated by the MPSC, to a review by the MPSC of the Company’s GCR gas purchase plan and the reasonableness of actual purchases and procurement practices. In Alaska, gas supply contracts are reviewed by the RCA at the time the Company enters into those contracts. As a result of the use of these mechanisms, in the absence of regulatory disallowances, for any increase or decrease in cost of gas sold, there is a corresponding increase or decrease in gas sales revenue. Refer to the caption “Cost of Gas, Gas Charges Recoverable from Customers, and Amounts Payable to Customers” in Note 1 of the Notes to the Consolidated Financial Statements in Item 8 of the Company’s 2005 Annual Report on Form 10-K for further information on cost of gas and the GCR mechanisms. Management generally evaluates changes in gas sales margin rather than gas sales revenue, due to the fluctuations caused by market-driven changes in cost of gas sold. Please refer to the Gas Sales Margin section below for a detailed variance analysis.

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PART I - FINANCIAL INFORMATION - (Continued)

Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations (Continued).

Gas Distribution Business Segment (Continued)

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2006			2005			2006			2005
	(dollars in thousands)
Gas sales revenues	$	55,294		$	53,976		$	398,899		$	351,592
Cost of gas sold		36,637			36,127			312,756			264,304
Gas sales margin	$	18,657		$	17,849		$	86,143		$	87,288
Gas transportation revenue		5,556			5,552			21,101			20,761
Other operating revenue		1,544			1,464			6,822			6,170
	$	25,757		$	24,865		$	114,066		$	114,219
Operation and maintenance		17,432			17,189			54,241			50,380
Depreciation and amortization		6,874			6,742			20,578			20,158
Property and other taxes		2,382			2,919			7,306			8,980
Operating income	$	(931	)	$	(1,985	)	$	31,941		$	34,701
Volumes of gas sold (MMcf)		5,392			4,949			41,440			43,287
Volumes of gas transported (MMcf)		12,767			14,015			40,042			41,593
Number of customers at end of period		408,405			402,819			408,405			402,819
Degree Days
Alaska		1,010			886			6,841			6,051
Michigan		166			90			3,858			4,334
Percent colder (warmer) than normal
Alaska		13.9	%		(0.9	)%		7.1	%		(6.6	)%
Michigan		(7.2	)%		(54.1	)%		(12.4	)%		(1.0	)%
The amounts in the above table include intercompany transactions.

Gas Sales Margin-The Company’s gas sales margin is derived primarily from customer service charges and consumption-based distribution charges. The customer service charges are fixed amounts charged to customers each month. Distribution charges vary each month because they are based on the volume of gas consumed by customers. There are four primary factors that have historically impacted gas sales margin and, in the Company’s view, may impact future gas sales margin. These factors are changes in: (i) customer gas consumption; (ii) the number of gas sales customers; (iii) LAUF gas expense; and (iv) customer rates, including gas cost savings. In addition to these recurring items, the Company sold excess gas to a third-party gas supplier in the second quarter of 2005, which increased gas sales margin for the nine-month period ended September 30, 2005, by approximately $1.4 million. There was no similar sale during the same period in 2006.

Changes in customer gas consumption from one year to another have historically been attributable primarily to the impact of changes in temperatures between periods. More recently, 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) have contributed more significantly than in the past to changes in customer gas consumption. During the three months ended September 30, 2006, an increase in customer gas consumption increased gas sales margin by approximately $0.4 million, when compared to the three months ended September 30, 2005. The increase in consumption during the third quarter of 2006, when compared to 2005, was due primarily to the impact of aggregate colder temperatures in the Company’s service territories, partially offset by the impact of customer conservation. A decrease in customer gas consumption during the nine months ended September 30, 2006, decreased gas sales margin by approximately $3.2 million, when compared to the same period ended September 30, 2005. The decrease in consumption was due to warmer temperatures and customer conservation during the nine months ended September 30, 2006, when compared to the nine months ended September 30, 2005.

- 38 -

PART I - FINANCIAL INFORMATION - (Continued)

Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations (Continued).

Gas Distribution Business Segment (Continued)

During the nine months ended September 30, 2006, actual consumption per gas sales customer in Michigan decreased by approximately 15.2% when compared to the same period ending September 30, 2005. In Alaska, there was an increase in actual consumption per gas sales customer of approximately 10.6% when comparing the same periods. Normalized consumption per gas sales customer decreased by an estimated 4.3% in Michigan and an estimated 3.6% in Alaska, when comparing the nine months ended September 30, 2006, to the nine months ended September 30, 2005. The Company believes the decrease in normalized gas consumption per gas sales customer was due in large part to conservation prompted, in part, by the increased cost of natural gas. In addition to the decrease in customer consumption caused by conservation, there was also a decrease in consumption as a result of temperatures in Michigan during the first nine months of 2006 that were approximately 11.0% warmer than during the same period of 2005. This was partially offset by the impact of temperatures in Alaska during the first nine months of 2006, which were approximately 13.1% colder than during the same period of 2005. For further details on customer consumption, refer to Management’s Discussion and Analysis under the captions “The Impact of Higher Natural Gas Prices” and “The Impact of Weather and Energy Conservation.”

The average number of gas distribution customers in Michigan (excluding customers acquired in the acquisition of Peninsular Gas Company in June 2005) and Alaska has increased annually by an average of 1.4% and 3.3%, respectively, during the past three years. For the nine-month period ended September 30, 2006, the average number of gas distribution customers in Michigan (excluding customers acquired in the acquisition of Peninsular Gas Company in June 2005) and Alaska increased by 0.6% and 3.5%, respectively, when compared to the nine-month period ended September 30, 2005. The additional customers increased gas sales margin for the three and nine months ended September 30, 2006, by approximately $0.2 and $1.3 million, respectively, when compared to the same periods ended September 30, 2005. Customers added to the Company’s Michigan operation as a result of the acquisition of Peninsular Gas Company contributed $0.5 million to gas sales margin during the nine months ended September 30, 2006, when compared to the same period ended September 30, 2005.

LAUF gas is a term used in the natural gas distribution industry to refer to the difference between the gas that is measured and injected into the Company’s gas distribution system and the amount of gas measured at customer meters. Typically, there is more gas measured as purchased and transported into a utility’s distribution pipeline system than is actually measured as sold and transported out of a utility’s distribution pipeline system. There are a number of reasons for LAUF gas, including measurement errors and leaks. The annual LAUF gas volumes in Michigan have ranged from 0.5% to 1.4% of total gas volumes sold and transported in Michigan over the last 10 years. A decrease in LAUF gas expense increased gas sales margin for the three months ended September 30, 2006, by approximately $0.1 million when compared to the three months ended September 30, 2005. An increase in LAUF gas expense decreased gas sales margin for the nine months ended September 30, 2006, by approximately $0.6 million when compared to the same period ended September 30, 2005. The cost of LAUF gas is affected by the underlying commodity cost and rate mechanisms employed to price LAUF gas volumes and recover this cost from customers.

The remainder of the change in gas sales margin for the nine months ended September 30, 2006, was due primarily to changes in rates and gas cost savings, as well as other miscellaneous factors. During the nine months ended September 30, 2006, these factors increased gas sales margin by approximately $2.3 million when compared to the nine months ended September 30, 2005. There was an increase in customer rates effective on March 30, 2005, for MPSC Division customers. The rate increase for MPSC Division customers was the result of a settlement agreement approved by the MPSC. The CCBC approved new rates for CCBC-regulated customers and the use of a GCR pricing mechanism, both of which were effective in April 2005. During the first three months of 2005, the Company’s service area regulated by the CCBC was not operating under a GCR pricing mechanism, and certain gas cost savings allowed under the terms of a gas supply and management agreement (which expired March 31, 2005) were retained by the Company. 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 the Company’s 2005 Annual Report on Form 10-K. For further information regarding the Company’s natural gas supply and management agreements, GCR pricing mechanisms and gas cost savings, refer to the caption “Cost of Gas, Gas Charges Recoverable from Customers, and Amounts Payable to Customers” in Note 1 of the Notes to the Consolidated Financial Statements in Item 8 of the Company’s 2005 Annual Report on Form 10-K.

- 39 -

PART I - FINANCIAL INFORMATION - (Continued)

Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations (Continued).

Gas Distribution Business Segment (Continued)

Gas Transportation Revenue -The Company provides gas transportation services to customers who typically consume large volumes of natural gas. These customers purchase their natural gas directly from third-party suppliers. The natural gas purchased by customers from third-party suppliers is then transported on the Company’s gas distribution system to the customers. For the three months ended September 30, 2006, gas transportation revenue was essentially unchanged when compared to the same period ended September 30, 2005. For the nine months ended September 30, 2006, gas transportation revenue increased by $0.3 million, when compared to the same period ended September 30, 2005. The primary reason for the $0.3 million increase for the nine months ended September 30, 2006, was an increase in transportation volumes to commercial customers as a result of colder weather in Alaskaand an increase in commercial transportation customers. These increases were partially offset by a decrease in transportation volumes for industrial and power plant customers, including the fertilizer manufacturer discussed below. While gas transportation revenues were higher for the nine months ended September 30, 2006, when compared to the same period September 30, 2005, total gas transportation volumes were lower when comparing the same periods, by 1,551 MMcf. This decline occurred because commercial customers are charged at higher tariff rates for the volumes of gas they transport than are industrial and power plant customers. Consequently, the revenues generated from the increase in volumes transported for commercial customers more than offset the decrease in revenues generated by the larger decrease in volumes transported for industrial and power plant customers.

One of the Company’s Alaska service area industrial transportation customers, a fertilizer manufacturer, has publicly announced that it has experienced difficulty in securing sufficient natural gas supplies at an appropriate price to continue operating in the future. The customer has indicated that it has secured sufficient natural gas supplies to operate at a reduced rate through October 2007, but currently does not have sufficient natural gas under contract at an appropriate price to operate after that date. Further, it expects to experience an extended shutdown during the winter months of 2006-2007 due to the lack of seasonal gas supply. Transportation revenues to this customer totaled $2.0 million in 2005. Based upon volumes transported during the first nine months of 2006 and estimates provided by the customer, transportation revenues to this facility are expected to total $1.2 million in 2006 and $0.8 million in 2007. The Company cannot predict the likely pattern of future operations at this plant, including whether the plant will ultimately close.

- 40 -

PART I - FINANCIAL INFORMATION - (Continued)

Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations (Continued).

Gas Distribution Business Segment (Continued)

Beginning October 1, 2006, Aurora Power Resources (“Aurora Power”), a third party marketer and an affiliate of Aurora, stopped supplying natural gas to approximately 90 of the Company’s transportation customers in Alaska. Aurora Power ceased deliveries to an additional 440 transportation customers as of November 1, 2006. As a result, the affected transportation customers have, or will likely, become gas sales customers of the Company. The gas for these new sales customers will be supplied under the Company’s existing long-term gas supply agreements. For all but one of these customers, the Company does not expect that this change from gas transportation service to gas sales service will affect the Company’s margins significantly, because the margins under either service are the same. The Company has negotiated a special contract with one of the affected transportation customers, a public utility, which would result in future gas sales margins that would be higher than the margins the Company earned previously from this customer for providing transportation service. This special contract has been put into effect, subject to RCA review and approval.

Other Operating Revenue - During thethree and nine months ended September 30, 2006, other operating revenue increased by $0.1 million and $0.7 million, respectively, when compared to the same periods ended September 30, 2005. The increase for the third quarter of 2006 was due primarily to an increase in pipeline management revenue. The increase for the nine months ended September 30, 2006, was due primarily to an increase in miscellaneous customer revenues. The miscellaneous customer revenues include various service fees and late payment fees charged to customers. The pipeline management revenue is earned by NORSTAR Pipeline Company (“NORSTAR”). NORSTAR is an indirect subsidiary of the Company, which provides pipeline management and pipeline construction management services to non-affiliated customers in Alaska.

Operations and Maintenance Expenses -For the three and nine months ended September 30, 2006, operations and maintenance (“O&M”) expenses increased by $0.2 million and $3.9 million, respectively, when compared to the same periods ended September 30, 2005. The $0.2 million change in O&M expenses between the third quarters of 2006 and 2005 was primarily due to increases in employee benefit costs. This same item as well as an increase in uncollectible customer accounts and a charge associated with the sublease of office space that was the Company’s former headquarters were the primary itemscausing the $3.9 million change in O&M expenses between the nine-month periods ended September 30, 2006, and September 30, 2005.

Employee benefit costs primarily include pension expense, medical coverage expense (including retiree medical coverage), and incentive compensation. For the three and nine months ended September 30, 2006, employee benefit costs increased by approximately $0.5 million and $2.4 million, respectively, when compared to the same periods ended September 30, 2005. Note 7 of the Condensed Notes to the Unaudited Consolidated Financial Statements provides details regarding pension and postretirement medical costs. Incentive compensation increased as a result of the Company’s adoption of SFAS 123-R on January 1, 2006, and the Company’s granting of additional share-based compensation.

Uncollectible customer accounts increased by approximately $0.9 million for the nine months ended September 30, 2006, when compared to the same period ended September 30, 2005. This increase was primarily attributable to higher gas prices (resulting in higher customer bills), reduced government funding of low income heating programs and rules limiting the ability of the Gas Distribution Business to terminate service to delinquent customers.

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PART I - FINANCIAL INFORMATION - (Continued)

Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations (Continued).

Gas Distribution Business Segment (Continued)

The Company’s O&M expenses for the nine months ended September 30, 2006, include a charge of $1.2 million as a result of efforts to mitigate future costs associated with the lease for the Company’s former headquarters. During the first quarter of 2006, the Company was able to sublease this office space at less than the original lease rate, resulting in an improvement of future cash flow but a charge to earnings under the applicable accounting rules. For additional information, refer to Note 8 of the Condensed Notes to the Unaudited Consolidated Financial Statements in Part 1, Item 1 of this Form 10-Q.

The remainder of the change in O&M expense between the three-month periods and between the nine-month periods was primarily due to changes in various other operating expenses.

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 upgraded and replaced, and the Company also typically upgrades and relocates parts of its system in connection with public works projects to improve roads and other public facilities. The increase in depreciation and amortization expense from period to period 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 decreased for the three and nine months ended September 30, 2006, by approximately $0.5 million and $1.7 million, respectively, when compared to the same periods ended September 30, 2005. The decreases are primarily the result of certain taxing jurisdictions in Michigan accepting the Company’s settlement offers related to outstanding property tax appeals. Refer to Note 13 of the Notes to the Consolidated Financial Statements in Item 8 of the Company’s 2005 Annual Report on Form 10-K for information about the property tax appeals and the recovery of prior year excess property taxes paid.

Regulatory and Other Matters - In May 2006, the Company filed a request with the MPSC seeking authority to increase the base rates the Company charges to customers in its service areas regulated by the MPSC by $18.9 million. As part of this filing, the Company also has proposed to change various aspects of the Company’s rate design (meaning the way in which the costs of providing service to customers is collected in base rates and other rates and charges). The Company expects the MPSC to decide the case by mid- to late-Spring 2007. The Company is unable to predict, however, either when the MPSC will act on the Company’s filing or the outcome of the MPSC proceeding. Refer to Note 9 of the Condensed Notes to the Unaudited Consolidated Financial Statements in Part 1, Item 1 of this Form 10-Q for information regarding the proposed increase in base rates, rate design proposals and other regulatory matters.

In April 2006, the Company received a letter from Aurora regarding the gas supply contract for natural gas deliveries to ENSTAR under the Moquawkie Contract. Aurora asserted that production under the Moquawkie Contract is “Not Economic” as that term is defined in the Moquawkie Contract and said that it would suspend, and subsequently did suspend, deliveries effective October 1, 2006. Refer to Note 8 and Note 9 of the Condensed Notes to the Unaudited Consolidated Financial Statements in Part 1, Item 1 of this Form 10-Q for information regarding the lawsuit the Company has filed against Aurora and steps the Company has taken to replace the suspended gas deliveries and recover the higher cost of the substitute gas.

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PART I - FINANCIAL INFORMATION - (Continued)

Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations (Continued).

Gas Distribution Business Segment (Continued)

In 2005, the Company entered into a gas supply contract with Marathon to supply a portion of the needs of the Company’s Alaska customers from 2009 through 2017. In November 2005, the Company submitted the gas supply contract to the RCA for its approval. In September 2006, the RCA rejected the Marathon Contract. Refer to Note 9 of the Condensed Notes to the Unaudited Consolidated Financial Statements in Part 1, Item 1 of this Form 10-Q for information regarding the RCA decision and the motions for reconsideration and/or clarification filed by the Company and other parties to the proceedings.

The Company has replaced the Customer Information System used for its Michigan operation. The Customer Information System is the primary computer program used to, among other things, bill customers for gas service. The Company put the system in service in October 2006 and is continuing to monitor its performance, which, to date, has been satisfactory.

Corporate and Other

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2006		2005		2006		2005
	(in thousands)
Operating revenues	$	4,049	$	3,286	$	12,064	$	11,732
Operating expenses		2,982		3,035		10,272		10,881
Operating income	$	1,067	$	251	$	1,792	$	851
The amounts in the above table include intercompany transactions.

Operating Revenues- Corporate and Other reported operating revenue of $4.0 million and $12.1 million, respectively, for the three- and nine-month periods ended September 30, 2006, compared to operating revenue of $3.3 million and $11.7 million, respectively, for the same periods ended September 30, 2005. The $0.7 million increase in revenues during the third quarter of 2006 when compared to the third quarter of 2005 was due to the sale of natural gas inventory and increases in IT services revenue. The $0.3 million increase in operating revenues when comparing the first nine months of 2006 to the first nine months of 2005 was due primarily to the sale of natural gas inventory.

Operating Income - For the three- and nine-month periods ended September 30, 2006, Corporate and Other reported operating income of $1.1 and $1.8 million, respectively, compared to operating income of $0.3 million and $0.9 million, respectively, for the same periods ended September 30, 2005. The $0.8 million increase when comparing the third quarter of 2006 to the third quarter of 2005 was due primarily to decreases in IT operating expenses and a $0.5 million reversal, during the third quarter of 2006, of a second quarter 2006 write down of natural gas inventory due to changes in market conditions. The $0.9 million increase in operating income during the nine-month period ended September 30, 2006, when compared to the nine-month period ended September 30, 2005, was due primarily to decreases in IT operating expenses and corporate professional fees.

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PART I - FINANCIAL INFORMATION - (Continued)

Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations (Continued).

Other Income and Deductions

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2006			2005			2006			2005
	(in thousands)
Interest expense	$	(10,270	)	$	(10,712	)	$	(31,000	)	$	(32,648	)
Debt extinguishment costs		-			(1,090	)		-			(1,456	)
Other income		664			856			2,027			2,004
Total other income (deductions)	$	(9,606	)	$	(10,946	)	$	(28,973	)	$	(32,100	)

Interest Expense - Interest expense for the three and nine months ended September 30, 2006, decreased by $0.4 million and $1.6 million, respectively, when compared to the same periods ended September 30, 2005. The decreases were primarily due to lower levels of long-term debt as a result of the redemption of $10.3 million and $30.9 million of the Company’s 10.25% Subordinated Notes in April 2005 and September 2005, respectively. The decrease in interest expense from lower levels of long-term debt was partially offset by higher average levels of short-term bank borrowings under the Company’s Bank Credit Agreement and an increase in short-term interest rates and associated financing costs related to the Company’s Bank Credit Agreement. The higher average level of short-term borrowings during 2006, was due primarily to the impact of recent high natural gas prices, which resulted in a need for additional working capital to finance gas purchases at higher market prices, finance storage inventory, and carry customer accounts receivable.

Debt Extinguishment Costs - For the three and nine months ended September 30, 2005, the Company’s Consolidated Statements of Operations reflect $1.1 million and $1.5 million, respectively, of debt extinguishment costs related to the redemption of $10.3 million and $30.9 million of the Company’s 10.25% Subordinated Notes in April 2005 and September 2005, respectively. The debt extinguishment costs represent the write-off of the balance of unamortized debt issuance costs related to the 10.25% Subordinated Notes. For further information regarding the redemption of the 10.25% Subordinated Notes, refer to Note 4 of the Notes to the Consolidated Financial Statements in Item 8 of the Company’s 2005 Annual Report on Form 10-K.

Other Income - Other income for the three months ended September 30, 2006, decreased by $0.2 million when compared to the same period ended September 30, 2005. Other income for the nine months ended September 30, 2006, was essentially unchanged. The decrease for the three months ended September 30, 2006, was primarily due to lower interest income. Interest income was also lower by approximately $0.2 million for the nine months ended September 30, 2006, but was offset by an increase in equity income from the Company’s gas storage partnership.

Income Taxes

Income tax expense (benefit) was $(3.6) million and $1.5 million, respectively, for the three and nine months ended September 30, 2006, and $(4.8) million and $1.0 million, respectively, for the same periods ended September 30, 2005. The change in income taxes, when comparing one period to another, is due primarily to changes in earnings before income taxes.

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PART I - FINANCIAL INFORMATION - (Continued)

Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations (Continued).

Dividends on Convertible Cumulative Preferred Stock

The Company issued 350,000 shares of Preferred Stock in the first quarter of 2005. The Preferred Stock and the cash dividends on the Preferred Stock are described in Note 2 of the Condensed Notes to the Unaudited Consolidated Financial Statements in Part 1, Item 1 of this Form 10-Q. Dividend expense for the Preferred Stock amounted to $0.6 million and $2.1 million, respectively, for the three- and nine-month periods ended September 30, 2006, and $0.9 million and $2.0 million, respectively, for the three- and nine-month periods ended September 30, 2005. The decrease in dividends for the third quarter was due primarily to the effect of the Company’s repurchase and subsequent retirement of 110,784 shares of the Preferred Stock in the second quarter of 2006. The increase in the dividends for the nine months ended September 30, 2006, when compared to the same period ended September 30, 2005, was due to the Preferred Stock not being issued until March 15, 2005, partially offset by the impact of the retirement of a portion of the Preferred Stock in the second quarter of 2006, as discussed above, including a gain of approximately $0.2 million associated with the repurchase. For further information on the repurchase and retirement of Preferred Stock, refer to Note 2 of the Condensed Notes to the Unaudited Consolidated Financial Statements in Part 1, Item 1 of this Form 10-Q.

Dividends and Repurchase Premium on Convertible Preference Stock

The CPS was repurchased in March 2005. These securities and the paid-in-kind, non-cash dividends on them are described in Note 4 of the Notes to the Consolidated Financial Statements in Item 8 of the Company’s 2005 Annual Report on Form 10-K. Non-cash dividends on these securities were $0.9 million for the nine months ended September 30, 2005. The Company’s Consolidated Statements of Operations for the nine months ended September 30, 2005, also include an $8.2 million premium associated with the repurchase of the CPS and Warrants.

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 nine months ended September 30, 2006, and 2005:

	Nine Months Ended
	September 30,
	2006			2005
	(in thousands)
Capital investments:
Property additions - gas distribution	$	(30,363	)	$	(27,494	)
Property additions - corporate and other		(230	)		(1,309	)
	$	(30,593	)	$	(28,803	)

The Company’s expenditures for property additions were approximately $30.6 million for the first nine months of 2006. Expenditures for property additions during the remainder of 2006 are anticipated to be approximately $11.5 million.

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PART I - FINANCIAL INFORMATION - (Continued)

Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations (Continued).

Liquidity and Capital Resources (Continued)

Cash Flows Provided By Operations - The Company’s net cash provided by operating activities totaled $93.8 million for the nine-month period ended September 30, 2006, compared to $58.6 million for the same period ended September 30, 2005. 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 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 during the months of November through March. The Company may also use significant amounts of short-term borrowings to finance natural gas purchases during the non-heating season. The change in cash provided by operating activities is also impacted by changes in the operating results of the Company’s businesses.

Cash Flows Provided By Financing - The Company’s net cash used for financing activities totaled $61.2 million for the nine-month period ended September 30, 2006, compared to $27.9 million for the same period ended September 30, 2005.

	Nine Months Ended
	September 30,
	2006			2005
	(in thousands)
Cash provided by (used for) financing activities:
Issuance of common stock, net of expenses	$	86		$	30,499
Issuance of convertible cumulative preferred stock, net of expenses		-			66,362
Repurchase of convertible cumulative preferred stock, net of expenses		(12,587	)		-
Repurchase of convertible preference stock and common stock warrants		-			(60,000	)
Repayment of notes payable and payment of related expenses		(46,400	)		(21,388	)
Repayment of long-term debt		(102	)		(41,354	)
Payment of dividends on convertible cumulative preferred stock		(2,221	)		(1,458	)
Change in book overdrafts included in current liabilities		36			(547	)
	$	(61,188	)	$	(27,886	)

On April 24, 2006, the Company issued 865,028 shares of the Company’s Common Stock and paid $5.0 million in cash to a holder of the Company’s Preferred Stock, in exchange for 50,884 shares of Preferred Stock, which were retired. On May 26, 2006, the Company issued 689,996 shares of the Company’s Common Stock and paid $7.6 million in cash to another holder of the Company’s Preferred Stock, in exchange for 59,900 shares of Preferred Stock, which were retired. The components of these transactions that do not involve the exchange of cash are not reflected in the Company’s Consolidated Statements of Cash Flows.

During the first quarter of 2005, the Company repurchased all of the CPS shares (52,543) and Warrants (905,565) held by a private equity firm. The aggregate purchase price for the CPS and Warrants was $60 million. During the first quarter of 2005, the Company also issued 350,000 shares of Preferred Stock. The gross proceeds from this offering were approximately $70 million, of which $60 million was used to fund the repurchase of CPS and Warrants. The remaining proceeds were used to redeem $10.3 million principal amount of the Company’s 10.25% Subordinated Notes held by SEMCO Capital Trust I on April 29, 2005. The Trust, in turn, used the proceeds to redeem 400,000 shares of its Trust Preferred Securities and 12,371 shares of its common securities. For further information regarding these transactions, refer to Note 4 of the Notes to the Consolidated Financial Statements in Item 8 of the Company’s 2005 Annual Report on Form 10-K.

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PART I - FINANCIAL INFORMATION - (Continued)

Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations (Continued).

Liquidity and Capital Resources (Continued)

Future Financing Plans - In general, the Company funds its capital expenditures with operating cash flows and borrowings under its Bank Credit Agreement. When appropriate, the Company will refinance its short-term debt with long-term debt, Common Stock issuances or other long-term financing instruments.

The Company’s capital structure at September 30, 2006, consisted of approximately 65.4% total debt (including current maturities and notes payable), 6.3% preferred stock and 28.3% common equity. The Company continues to assess its overall liquidity and capital structure, with a view to migrating over time to a capital structure that is consistent with that of an investment grade company. One of the Company’s primary goals is to increase equity as a percentage of total capital while reducing the Company’s overall debt to total capital ratio. Although there are no current specific plans to issue equity or reduce debt during the remainder of 2006 other than discussed below, the Company will continue to identify and, as appropriate, take advantage of market opportunities to do so as they arise.

On October 31, 2006, the Company entered into a bank term loan agreement in the amount of $55 million. The term loan matures on June 30, 2016 and is callable at any time at the option of the Company. Interest on the loan is payable at variable rates based on LIBOR, plus an applicable margin. The Company expects to receive the proceeds of the loan on or about November 29, 2006. The proceeds will be used to retire a portion of the $59.5 million principal amount outstanding of the Company’s 8% Series Notes due 2016. On November 1, 2006, the Company called for redemption of the $59.5 million of 8% Senior Notes due 2016, at a redemption price equal to 100% of the principal amount plus accrued interest. The notes will be redeemed on November 30, 2006.

On October 13, 2006, the Company established an unsecured $15 million discretionary bank line of credit (“Line of Credit”) that expires on October 1, 2007. The bank is not obligated to make any advances under the Line of Credit and may at any time, without notice, in its sole and absolute discretion, refuse to make advances to the Company. Interest paid under the Line of Credit is at variable rates, which are based upon prime lending rates or rates quoted by the bank.

As part of its general financing plans, the Company intends to enter into several similar unsecured discretionary lines of credit with other lenders to provide several alternative sources from which the Company could obtain short-term financing, depending on which source would provide financing on terms the Company evaluates as best under the circumstances. The Company anticipates that, under these arrangements with various lenders, at any given time, its total outstanding advances under the current Line of Credit and any such future similar financing arrangements, collectively, will not exceed $15 million. The Company currently intends to use amounts advanced under such arrangements primarily to finance the Company’s working capital needs. The advances under these arrangements may fluctuate materially, given the seasonality of the Company’s business.

The Company has an unsecured $120 million revolving Bank Credit Agreement, which expires on September 15, 2008. Interest paid under the terms of the Bank Credit Agreement is at variable rates, which are based on LIBOR or prime lending rates, plus applicable margins. LIBOR-based borrowings are permitted for periods ranging from two weeks to one, two, three or six months. At September 30, 2006, the Company was utilizing $32.8 million of the borrowing capacity available under the Bank Credit Agreement, leaving approximately $87.2 million of the borrowing capacity unused. The $32.8 million of capacity being used consisted of $0.3 million of letters of credit and $32.5 million of borrowings. These amounts will change from time to time, reflecting the Company’s then current working capital needs. Refer to Note 2 of the Condensed Notes to the Unaudited Consolidated Financial Statements in Part 1, Item 1 of this Form 10-Q for additional information regarding the Bank Credit Agreement, including a description of the covenants contained therein. As of September 30, 2006, the Company was in compliance with the Bank Credit Agreement covenants.

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PART I - FINANCIAL INFORMATION - (Continued)

Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations (Continued).

Liquidity and Capital Resources (Continued)

The Company’s Gas Distribution Business is seasonal in nature. During the winter heating season, higher volumes of gas are sold, resulting in peak profitability during the fourth and first quarters of the year. The Company’s cash flow and its corresponding use of its Bank Credit Agreement and lines of credit typically also will follow a seasonal pattern. The Company expects to use funds available under the Bank Credit Agreement and lines of credit to finance, on a short-term basis, the variability and seasonality of its operating cash flow and working capital requirements. Typically, as the Company collects cash from winter heating sales in the latter part of the first quarter and the second quarter, it will pay down the borrowings under the Bank Credit Agreement and lines of credit. During the summer months, it will reduce its short-term borrowings under the Bank Credit Agreement and lines of credit, and may build up sufficient cash to enable it to enter into short-term investments. As gas is purchased throughout the summer and injected into storage in preparation for the winter heating season and the Company completes its annual construction program, the Company expects to incur borrowings under the Bank Credit Agreement and lines of credit. Such borrowings typically begin during the third quarter and intensify, such that the maximum short-term borrowings occur around the end of the year. As winter sales occur and gas sales revenues are billed and collected, the Company again begins to reduce its short-term borrowings in the first quarter.

This borrowing pattern is affected by numerous items, including the credit terms under which the Company purchases natural gas for sale to customers, its GCR factors in various jurisdictions and its relative levels of gas storage inventory. Throughout the first three quarters of 2006, the Company’s volume of natural gas in storage has been higher, on average, than what has been typical during the same period of prior years. This increase in storage volumes was due in large part to reduced sales volumes in Michigan related to warmer than normal weather and conservation. The Company has financed this higher volume of gas in storage by utilizing its Bank Credit Agreement, which has resulted in a higher level of short term borrowings, on average, throughout 2006, when compared to 2005. Refer to the discussion in Management’s Discussion and Analysis, under the caption “The Impact of Higher Natural Gas Prices,” for information regarding additional working capital requirements that have also resulted from increases in the price of natural gas. The Company generally plans to have its underground storage fields filled to or near capacity by October of each year in anticipation of the upcoming winter heating season. While the Company anticipates its short-term borrowings will peak near year-end, it also currently expects to have a higher amount of unused short-term debt capacity when compared to December 31, 2005.

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.

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

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PART I - FINANCIAL INFORMATION - (Continued)

Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations (Continued).

New Accounting Standards Not Yet Effective

In June 2006, the FASB issued Financial Interpretation Number (‘‘FIN’’) 48, ‘‘Accounting for Uncertainty in Income Taxes - an interpretation of SFAS No. 109’’. In September 2006, the FASB issued SFAS 157, “Fair Value measurements” and SFAS 158, “Employers’ Accounting Defined Benefit Pension and Other Postretirement Plans, an amendment of FASB Statements No. 87, 88, 106, and 132(R).” Refer to the “New Accounting Standards Not Yet Effective” section of Note 1 of the Condensed Notes to the Unaudited Consolidated Financial Statements in Part 1, Item 1, of this Form 10-Q for information on these new accounting standards.

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PART I - FINANCIAL INFORMATION - (Continued)

Item 3.Quantitative and Qualitative Disclosures About Market Risk.

For the information required pursuant to this item, refer to Item 7A in the Company’s 2005 Annual Report on Form 10-K and Note 3 of the Condensed Notes to Unuadited Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q.

Item 4.Controls and Procedures.

Disclosure Controls and Procedures - As of the end of the period covered by this report, the Company carried out an evaluation, under the supervision and with the participation of management, including the Chief Executive Officer (“CEO”) and the Chief Financial Officer (“CFO”), of the effectiveness of the design and operation of the Company’s disclosure controls and procedures as defined in Rules 13a-15(e) and 15d-15(e) of the Securities and Exchange Act of 1934, as amended (the “Exchange Act”). Based on that evaluation, the CEO and the CFO have concluded that the Company’s disclosure controls and procedures were effective as of September 30, 2006 in timely alerting them to the information relating to the Company required to be disclosed in the Company’s periodic reports filed with the SEC. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that the Company’s disclosure controls and procedures will detect or uncover every situation involving the failure of persons within the Company to disclose material information otherwise required to be set forth in the Company’s periodic reports; however, the Company’s disclosure controls are designed to provide reasonable assurance that they will achieve their objective of timely alerting the CEO and CFO to the information relating to the Company required to be disclosed in the Company’s periodic reports required to be filed with the SEC.

Changes in Internal Control Over Financial Reporting - During the quarter ended September 30, 2006, no changes in the Company’s internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) of the Exchange Act) occurred that has materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting.

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PART II - OTHER INFORMATION

Item 1.Legal Proceedings.

For information on legal proceedings, refer to Note 8 of the Condensed Notes to the Unaudited Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q.

Item 1A.  Risk Factors.

None.

Item 2.Unregistered Sales of Equity Securities and Use of Proceeds.

During the fourth quarter of 2006, the Company issued five shares of its Common Stock pursuant to its Employee Stock Gift Program in reliance on exemptions from registration under the Securities Act of 1933, as amended, including Section 4(2) thereof.

Item 3.Defaults Upon Senior Securities.

None.

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

None.

Item 5.Other Information.

None.

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PART II - OTHER INFORMATION (Continued)

Item 6.Exhibits.

The following exhibits are filed herewith. (See page 54 for the Exhibit Index.)

Exhibits	Description
3.1	Articles of Incorporation of the Company, as restated August 30, 2006.
3.2	Amended and Restated Bylaws of the Company, as amended through August 16, 2006.
10.18.2	First Amendment to the SEMCO Energy, Inc. Short-Term Incentive Plan, effective January 1, 2006.
10.22.3	Second Amendment dated November 2, 2006, to Second Amended and Restated Credit Agreement, dated as of September 15, 2005, by and among the Company, various financial institutions, and LaSalle Bank Midwest National Association, Administrative Agent (incorporated herein by reference to Exhibit 10.3 to the Company’s Form 8-K filed November 2, 2006).
10.38 *	Retirement Agreement between the Company and John M. Albertine dated October 9, 2006 (incorporated herein by reference to Exhibit 10.1 to the Company’s Form 8-K filed October 10, 2006).
10.39	Master Revolving Note between the Company and Comerica Bank dated October 1, 2006 (incorporated herein by reference to Exhibit 10.1 to the Company’s Form 8-K filed October 17, 2006).
10.40	Negative Pledge Agreement between the Company and Comerica Bank dated October 1, 2006 (incorporated herein by reference to Exhibit 10.2 to the Company’s Form 8-K filed October 17, 2006).
10.41	Term Loan Agreement between the Company and Union Bank of California, N.A., dated October 31, 2006 (incorporated herein by reference to Exhibit 10.1 to the Company’s Form 8-K filed November 2, 2006).
31.1	CEO Certification, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2	CFO Certification, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1	CEO and CFO Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

*Indicates management contract or compensatory plan or arrangement.

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

	SEMCO ENERGY, INC. (Registrant)
Date:  November 6, 2006	By:	/s/ Michael V. Palmeri
		Senior Vice President and Chief Financial Officer and Treasurer (duly authorized officer, principal financial and chief accounting officer)

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EXHIBIT INDEX

Form 10-Q

Third Quarter 2006

Exhibits	Description
3.1	Articles of Incorporation of the Company, as restated August 30, 2006.
3.2	Amended and Restated Bylaws of the Company, as amended through August 16, 2006.
10.18.2	First Amendment to the SEMCO Energy, Inc. Short-Term Incentive Plan, effective January 1, 2006.
10.22.3	Second Amendment dated November 2, 2006, to Second Amended and Restated Credit Agreement, dated as of September 15, 2005, by and among the Company, various financial institutions, and LaSalle Bank Midwest National Association, Administrative Agent (incorporated herein by reference to Exhibit 10.3 to the Company’s Form 8-K filed November 2, 2006).
10.38 *	Retirement Agreement between the Company and John M. Albertine dated October 9, 2006 (incorporated herein by reference to Exhibit 10.1 to the Company’s Form 8-K filed October 10, 2006).
10.39	Master Revolving Note between the Company and Comerica Bank dated October 1, 2006 (incorporated herein by reference to Exhibit 10.1 to the Company’s Form 8-K filed October 17, 2006).
10.40	Negative Pledge Agreement between the Company and Comerica Bank dated October 1, 2006 (incorporated herein by reference to Exhibit 10.2 to the Company’s Form 8-K filed October 17, 2006).
10.41	Term Loan Agreement between the Company and Union Bank of California, N.A., dated October 31, 2006 (incorporated herein by reference to Exhibit 10.1 to the Company’s Form 8-K filed November 2, 2006).
31.1	CEO Certification, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2	CFO Certification, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1	CEO and CFO Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

*Indicates management contract or compensatory plan or arrangement.

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