Semco Energy (SEN) 10-Q 2006 Q2 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 June 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 July 31, 2006: 35,381,479

TABLE OF CONTENTS FOR FORM 10-Q

For Quarter Ended June 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	26
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	45
Item 4.	Controls and Procedures	45
PART II - OTHER INFORMATION
Item 1.	Legal Proceedings	46
Item 1A.	Risk Factors	46
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	46
Item 3.	Defaults upon Senior Securities	46
Item 4.	Submission of Matters to a Vote of Security Holders	46
Item 5.	Other Information	46
Item 6.	Exhibits	47
Signatures		48
Exhibit Index		49

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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						Six Months Ended
	June 30,						June 30,
		2006			2005			2006			2005
	(In thousands, except per share amounts)
OPERATING REVENUES
Gas sales	$	87,122		$	85,884		$	343,605		$	297,616
Gas transportation		6,153			5,981			15,545			15,209
Other		3,760			3,768			9,361			9,368
		97,035			95,633			368,511			322,193
OPERATING EXPENSES
Cost of gas sold		63,515			60,581			276,119			228,177
Operations and maintenance		19,565			17,666			39,198			36,241
Depreciation and amortization		7,218			7,147			14,367			14,125
Property and other taxes		2,174			3,096			5,230			6,364
		92,472			88,490			334,914			284,907
OPERATING INCOME		4,563			7,143			33,597			37,286
OTHER INCOME (DEDUCTIONS)
Interest expense		(10,181	)		(10,860	)		(20,730	)		(21,936	)
Debt extinguishment costs		-			(366	)		-			(366	)
Other		807			620			1,363			1,148
		(9,374	)		(10,606	)		(19,367	)		(21,154	)
INCOME (LOSS) BEFORE INCOME TAXES		(4,811	)		(3,463	)		14,230			16,132
INCOME TAX (EXPENSE) BENEFIT		1,835			1,350			(5,068	)		(5,749	)
NET INCOME (LOSS)		(2,976	)		(2,113	)		9,162			10,383
DIVIDENDS ON CONVERTIBLE CUMULATIVE PREFERRED STOCK		506			945			1,454			1,097
DIVIDENDS AND REPURCHASE PREMIUM ON CONVERTIBLE PREFERENCE STOCK		-			-			-			9,112
NET INCOME (LOSS) AVAILABLE TO COMMON SHAREHOLDERS	$	(3,482	)	$	(3,058	)	$	7,708		$	174
EARNINGS (LOSS) PER SHARE
Basic	$	(0.10	)	$	(0.11	)	$	0.23		$	0.01
Diluted	$	(0.10	)	$	(0.11	)	$	0.21		$	0.01
AVERAGE COMMON SHARES OUTSTANDING
Basic		34,618			28,494			34,111			28,460
Diluted		34,618			28,494			42,720			28,516
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
	June 30,		December 31,
	2006		2005
	(In thousands)
CURRENT ASSETS
Cash and cash equivalents	$	1,711	$	4,124
Restricted cash		3,637		1,590
Receivables, less allowances of $3,095 and $1,758		31,213		64,584
Accrued revenue		10,865		71,615
Gas in underground storage, at average cost		85,273		93,065
Deferred income taxes		7,044		5,345
Prepaid expenses		10,123		15,307
Materials and supplies, at average cost		5,757		4,970
Regulatory asset - gas charges recoverable from customers		877		971
Other		1,195		1,114
		157,695		262,685
PROPERTY, PLANT AND EQUIPMENT
Gas distribution		755,301		735,052
Corporate and other		38,939		39,879
		794,240		774,931
Less - accumulated depreciation		208,513		197,543
		585,727		577,388
DEFERRED CHARGES AND OTHER ASSETS
Goodwill		143,374		143,374
Regulatory assets		12,422		12,602
Unamortized debt expense		8,949		10,057
Other		13,041		10,449
		177,786		176,482
TOTAL ASSETS	$	921,208	$	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
	June 30,			December 31,
	2006			2005
	(In thousands, except for number
	of shares and par values)
CURRENT LIABILITIES
Notes payable	$	31,200		$	78,900
Accounts payable		19,658			64,557
Customer advance payments		11,771			22,043
Regulatory liability - amounts payable to customers		8,077			12,281
Pension and other postretirement costs		7,100			7,100
Accrued interest		4,339		��	4,616
Other		11,378			8,806
		93,523			198,303
DEFERRED CREDITS AND OTHER LIABILITIES
Regulatory liabilities		60,251			59,214
Deferred income taxes		39,782			30,715
Customer advances for construction		16,623			17,263
Pension and other postretirement costs		5,791			3,490
Other		6,476			5,385
		128,923			116,067
LONG-TERM DEBT		441,641			441,659
CONVERTIBLE CUMULATIVE PREFERRED STOCK
$1 par value; 500,000 shares authorized; 350,000 shares outstanding		45,567			66,526
COMMON SHAREHOLDERS' EQUITY
Common stock - $1 par value; 100,000,000 shares authorized; 35,369,963 and 33,704,025 shares outstanding		35,370			33,704
Capital surplus		249,274			241,944
Unearned compensation associated with restricted stock		-			(795	)
Accumulated comprehensive income (loss)		(9,018	)		(9,073	)
Retained earnings (deficit)		(64,072	)		(71,780	)
		211,554			194,000
TOTAL LIABILITIES AND CAPITALIZATION	$	921,208		$	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)
	Six Months Ended
	June 30,
	2006			2005
	(In thousands)
CASH FLOWS PROVIDED BY (USED FOR) OPERATING ACTIVITIES
Net income	$	9,162		$	10,383
Adjustments to reconcile net income to net cash provided by (used for) operating activities:
Depreciation and amortization		14,367			14,125
Amortization of debt costs and debt basis adjustments included in interest expense		1,703			1,878
Deferred income taxes and amortization of investment tax credits		7,368			96
Non-cash share-based compensation		913			305
Debt extinguishment costs		-			366
Changes in operating assets and liabilities and other, excluding the impact of business acquisitions and divestitures:
Receivables, net		33,370			7,576
Accrued revenue		60,750			45,541
Prepaid expenses		5,184			8,115
Materials, supplies and gas in underground storage		7,005			10,130
Regulatory asset - gas charges recoverable from customers		95			159
Accounts payable		(44,900	)		(12,409	)
Customer advances and amounts payable to customers		(15,116	)		(7,945	)
Other		4,817			221
NET CASH PROVIDED BY OPERATING ACTIVITIES		84,718			78,541
CASH FLOWS PROVIDED BY (USED FOR) INVESTING ACTIVITIES
Property additions - gas distribution		(21,280	)		(15,289	)
Property additions - corporate and other		(120	)		(1,182	)
Business acquisition, net of cash acquired		-			(2,797	)
Property retirement costs, net of proceeds from property sales		(154	)		(418	)
Equity contribution to gas storage partnership		(1,930	)		-
Proceeds from partial redemption of investment in unconsolidated subsidiary		-			309
Changes in restricted cash		(2,047	)		(2	)
NET CASH USED FOR INVESTING ACTIVITIES		(25,531	)		(19,379	)
CASH FLOWS PROVIDED BY (USED FOR) FINANCING ACTIVITIES
Issuance of common stock, net of expenses		43			545
Issuance of convertible cumulative preferred stock, net of expenses		-			66,397
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		(47,700	)		(39,300	)
Repayment of long-term debt		(92	)		(10,334	)
Payment of dividends on convertible cumulative preferred stock		(1,623	)		(583	)
Change in book overdrafts included in current liabilities		359			5
NET CASH USED FOR FINANCING ACTIVITIES		(61,600	)		(43,270	)
CASH AND CASH EQUIVALENTS
Net increase		(2,413	)		15,892
Beginning of period		4,124			2,118
End of period	$	1,711		$	18,010
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						Six Months Ended
	June 30,						June 30,
	2006			2005			2006		2005
	(In thousands)
NET INCOME (LOSS)	$	(2,976	)	$	(2,113	)	$	9,162	$	10,383
Valuation adjustment for marketable securities, net of income tax (expense) benefit of $4, $6, $(15) and $0		(9	)		23			27		13
Unrealized derivative gain on an interest rate hedge from an investment in an affiliate		-			-			28		63
COMPREHENSIVE INCOME (LOSS)	$	(2,985	)	$	(2,090	)	$	9,217	$	10,459
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 285,000 customers in Michigan and approximately 124,000 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 that do not meet the quantitative thresholds required to be reportable business segments (“non-separately reportable business segments”) are combined and included with the Company’s corporate division in a category the Company refers to as “Corporate and Other.” The Company’s non-separately reportable business segments primarily include operations and investments in information technology (“IT”) services, propane distribution, intrastate natural gas pipelines, and 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 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.

Gas in Underground Storage - During 2006, SEMCO Energy Ventures, Inc. (“Ventures”), a non-regulated subsidiary of the Company, purchased natural gas inventory for the business reasons discussed in Note 3. This natural gas inventory is subject to lower of average cost or market accounting. During the second quarter of 2006, the Company decreased the carrying value of Ventures’ natural gas inventory by approximately $0.5 million to reflect the value of this inventory at the market price on June 30, 2006. This writedown is reflected in operations and maintenance expense in the Company’s Consolidated Statements of Operations for the three and six months ended June 30, 2006.

The majority of the Company’s gas in underground storage is held by the Gas Distribution Business for sale to customers in Michigan. This inventory is also subject to lower of average cost or market accounting. However, the Gas Distribution Business is subject to regulation and operates with a regulator-approved gas cost recovery (“GCR”) pricing mechanisms, which are designed so that, in the absence of any cost disallowances, the Company’s cost of gas purchased is recovered in full from customers. As a result of this form of regulation, the cost of gas in underground storage held by the Gas Distribution Business is generally not written down. If costs are disallowed by regulators, such costs are deducted in cost of gas in the Company’s Consolidated Statements of Operations in the period of disallowance.

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SEMCO ENERGY, INC.

CONDENSED NOTES TO THE UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

(Continued)

Note 1 - Significant Accounting Policies (Continued)

Revenue Recognition -During the second quarter of 2006, Ventures sold approximately 92 million cubic feet (“MMcf”) of gas held in storage for delivery in September and October 2006. These future or forward sales, which are expected to generate aggregate revenues and gross margins of approximately $0.7 million and less than $0.1 million, respectively, will not be recorded in the Company’s consolidated financial statements until the periods when the gas is delivered. For further information regarding the sales of inventory held by Ventures, refer to Note 3.

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 which could impact the value of the Company’s business segments. If an impairment test of goodwill shows that the carrying amount of the goodwill is in excess of the fair value, a corresponding impairment loss would be recorded in the Consolidated Statements of Operations.

The 2006 annual impairment tests for the Company’s business units will be conducted during the third and fourth quarters of 2006. There were no changes in the carrying amount of goodwill for the six-month period ended June 30, 2006.

	Gas		Corporate
	Distribution		and		Total
	Segment		Other		Company
	(in thousands)
Goodwill as of December 31, 2005 and June 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 statement also amends SFAS 95, “Statement of Cash Flows,” to require that excess tax benefits related to the excess of the share-based compensation deductible for tax purposes over the compensation recognized for financial reporting purposes be classified as cash inflows from financing activities rather than as a reduction of taxes paid in operating activities. The Company adopted this statement 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 six months ended June 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 original provisions of 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.

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SEMCO ENERGY, INC.

CONDENSED NOTES TO THE UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

(Continued)

Note 1 - Significant Accounting Policies (Continued)

Prior to the adoption of SFAS 123-R, the Company accounted for share-based compensation arrangements in accordance with SFAS 123, “Accounting for Stock-Based Compensation,” as amended by SFAS 148, “Accounting for Stock-Based Compensation — Transition and Disclosure” (collectively “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:

	Three			Six
	Months Ended			Months Ended
	June 30,			June 30,
	2005			2005
	(in thousands, except per share amounts)
Net income (loss) available to common shareholders
As reported	$	(3,058	)	$	174
Add back share-based compensation expense included in reported net income, net of related tax effects		153			198
Deduct total share-based compensation expense determined under fair value based method for all awards, net of related tax effects		221			333
Pro forma	$	(3,126	)	$	39
Earnings (loss) per share - basic
As reported	$	(0.11	)	$	0.01
Pro forma	$	(0.11	)	$	-
Earnings (loss) per share - diluted
As reported	$	(0.11	)	$	0.01
Pro forma	$	(0.11	)	$	-

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 June 30, 2006, and $0.3 million and $0.2 million lower, respectively, for the six months ended June 30, 2006, than if the Company had continued to account for share-based compensation under APB 25. The reductions in earnings reduced basic earnings per share by $0.01 for the six months ended June 30, 2006, but were insufficient to cause a change in basic and diluted earnings per share for the three months ended June 30, 2006, and in diluted earnings per share for the six months ended June 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 an enterprise’s financial statements in accordance with SFAS No. 109, “Accounting for Income Taxes.” FIN 48 prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax 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 2 - Short-Term Borrowings and Capitalization

Short-Term Borrowings - 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 June 30, 2006, the Company was utilizing $34.1 million of the borrowing capacity available under the Bank Credit Agreement, leaving approximately $85.9 million of the borrowing capacity unused. The $34.1 million of capacity being used consisted of $2.9 million of letters of credit and $31.2 million of borrowings.

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 June 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 May 15, 2006, the Company paid dividends on its Preferred Stock totaling approximately $0.7 million, or $2.50 per share. The Company’s Board of Directors also has declared a dividend on the Preferred Stock payable on August 15, 2006, at a rate of $2.50 per share, to holders of record on August 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, resulting in there being 239,216 shares of Preferred Stock outstanding at June 30, 2006. For further information on these transactions, see the section below captioned “Common Shareholder’s Equity.”

Common Shareholder’s Equity -During the three and six months ended June 30, 2006, the Company issued 10,558 shares and 19,297 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 six months ended June 30, 2006, the Company issued 43,195 shares and 89,417 shares, respectively, of its Common Stock to certain of the Company's employee benefit plans.

- 12 -

SEMCO ENERGY, INC.

CONDENSED NOTES TO THE UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

(Continued)

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

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. 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. 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 three and six months ended June 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 type 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 (hereinafter collectively referred to as “SFAS 133”). SFAS 133 requires that every derivative instrument (including certain derivative instruments embedded in other contracts) be recorded in the statement of financial position, as either an asset or liability, measured at its fair value. SFAS 133 also requires that changes in the derivative’s fair value be recognized currently in earnings unless specific hedge accounting criteria are met. Special accounting for qualifying hedges allows a derivative’s gains and losses to offset related results on the hedged item in the statement of operations, and requires that a company must 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.

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.

- 13 -

SEMCO ENERGY, INC.

CONDENSED NOTES TO THE UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

(Continued)

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

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 June 30, 2006, included a liability of $2.1 million and a decrease in long-term debt of $2.1 million for this interest rate swap.

During the second quarter of 2006, the Company initiated a program to manage a portion of its commodity price risk. The program is designed to offset increases and decreases in lost and unaccounted-for (“LAUF”) gas expense that result from fluctuations in natural gas prices, in the portion of the Company’s Gas Distribution Business regulated by the MPSC (the “MPSC Division”). In the MPSC Division, LAUF gas expense is currently recovered from customers at an amount set in base rates. If the MPSC Division’s cost of gas is higher than the amount in base rates, the Company, in effect, does not recover its full LAUF gas expense from MPSC Division customers. To manage this risk, in April 2006, Ventures, a non-regulated subsidiary of the Company, purchased 422 MMcf of natural gas inventory, which is approximately equal to the estimated LAUF volumes for the 2006-2007 MPSC Division GCR plan year. Ventures also purchased interruptible storage for the volumes of gas purchased. During the second quarter of 2006, Ventures sold approximately 92 MMcf of the gas inventory for delivery in September and October of 2006, and plans to sell the remaining gas inventory on the open market at various times during the period from July 2006 through March 2007. For information regarding the accounting treatment of these forward sales and the accounting for Ventures’ gas inventory in underground storage, refer to Note 1. Under this risk management program, if natural gas prices increase, MPSC Division LAUF gas expense would also increase but the Company would expect the increase in LAUF gas expense to be offset, to a large extent, by gains from the sale of gas held by Ventures. If natural gas prices decrease, MPSC Division LAUF gas expense would also decrease, but the Company would expect the decrease in LAUF gas expense to be offset, to a large extent, by losses from the sale of gas held by Ventures. The actual results under this program may vary from expected results due to various factors, including the amount of actual MPSC Division LAUF volumes, when MPSC Division LAUF volumes are actually experienced, the timing of the sales of Ventures’ gas inventory and whether Ventures will be required to sell its gas inventory earlier than desired because such inventory is held in interruptible storage.

Note 4 - Share-Based Compensation

The Company’s 2004 Stock Award and Incentive Plan (“2004 Plan”), provides for, in various forms, the issuance 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 in greater detail below.

- 14 -

SEMCO ENERGY, INC.

CONDENSED NOTES TO THE UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

(Continued)

Note 4 - Share-Based Compensation (Continued)

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.

At June 30, 2006, there were approximately 540,000 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 six-month periods ended June 30, 2006, and 2005. The Company recognized expense related to its share-based compensation arrangements of $0.5 million and $0.9 million during the three and six months ended June 30, 2006, respectively, and $0.2 million and $0.3 million during the three and six months ended June 30, 2005, respectively. The tax benefit recognized in income in relation to this compensation expense was $0.2 million and $0.3 million, during the three and six months ended June 30, 2006, respectively, and was less than $0.1 million and was $0.1 million during the three and six months ended June 30, 2005, respectively. The Company did not capitalize any expense related to its share-based arrangements during the three and six months ended June 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. 14,728 of the RSUs issued in 2005 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 June 30, 2006, and changes during the six-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 June 30, 2006		40,978		$	6.18

 

- 15 -

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 six months ended June 30, 2005, 2,500 RSUs were granted to an executive with a weighted average grant date fair value of $5.92 per unit. No RSUs were granted to executives during the six months ended June 30, 2006. During the six months ended June 30, 2005, and June 30, 2006, 20,000 RSUs with a total fair value of $0.1 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 convert to shares of Common Stock until 2007. As of June 30, 2006, there was a total of 63,750 RSUs earned and vested. As of June 30, 2006, there was $0.2 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 1.3 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 PSU’s, which is referred to as the “Target Grant.” During the first six months of 2006, and 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 is terminated prior to the end of the vesting period due to the consummation of a change in control, 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 June 30, 2006, and changes during the six-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		-		-
Non-vested at June 30, 2006		394,372	$	5.72

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 six months ended June 30, 2006, and $6.15 per unit during the six months ended June 30, 2005. There were no PSUs settled in shares of Common Stock during the six months ended June 30, 2006, and 2005. As of June 30, 2006, there was $1.5 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 2.2 years.

- 16 -

SEMCO ENERGY, INC.

CONDENSED NOTES TO THE UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

(Continued)

Note 4 - Share-Based Compensation (Continued)

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

A summary of information regarding non-vested restricted stock as of June 30, 2006, and changes during the six-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 June 30, 2006		113,000		$	5.83

The grant date fair value of a share of restricted stock is equal to the price of a share of the Company’s Common Stock on the grant date. During the six months ended June 30, 2006, and June 30, 2005, 8,500 shares and 168,250 shares, respectively, of restricted stock were granted with a weighted average grant date fair value of $5.42 per share and $5.83 per share, respectively. During the six months ended June 30, 2006, and June 30, 2005, 57,000 shares and 7,250 shares, respectively, of restricted stock were vested. The total value of shares vested during the six-month periods ended June 30, 2006, and June 30, 2005, were $0.3 million and less than $0.1 million, respectively. As of June 30, 2006, there was $0.7 million of total unrecognized compensation cost related to non-vested restricted stock granted under the 2004 Plan. That cost is expected to be recognized over a weighted-average period of 1.5 years.

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. 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:

	Six Months Ended
	June 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

 

- 17 -

SEMCO ENERGY, INC.

CONDENSED NOTES TO THE UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

(Continued)

Note 4 - Share-Based Compensation (Continued)

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 June 30, 2006, and changes during the six-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		-		-
Outstanding at June 30, 2006		1,351,731	$	7.96		6.80	$	206
Exercisable at June 30, 2006		912,116	$	9.12		5.77	$	147

The weighted-average grant date fair value of options granted during the six months ended June 30, 2006, and 2005, was $2.11 and $2.59, respectively. During the six months ended June 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 June 30, 2006, there was $0.9 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 1.9 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”). 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.

- 18 -

SEMCO ENERGY, INC.

CONDENSED NOTES TO THE UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

(Continued)

Note 5 - Earnings Per Share (Continued)

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

	Three Months Ended				Six Months Ended
	June 30,				June 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		7,569		9,150		8,355		5,384
Assumed conversion of convertible preference stock		-		-		-		3,256
Assumed exercise of stock options		18		27		18		35
Assumed settlement of restricted stock units and performance share units		186		13		190		21
Assumed vesting of non-vested restricted stock		47		-		46		-
Potential income statement adjustments when calculating diluted earnings per share
Eliminate dividends on convertible cumulative preferred stock assumed converted	$	506	$	945	$	1,454	$	1,097
Eliminate dividends and repurchase premium on convertible preference stock assumed converted	$	-	$	-	$	-	$	9,112

- 19 -

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 six months ended June 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						Six Months Ended
	June 30,						June 30,
	2006			2005			2006			2005
	(in thousands, except per share amounts)
Average common shares outstanding
Issued		34,731			28,479			34,231			28,452
Adjustments to reconcile to average common shares outstanding for purposes of computing basic EPS:
Subtract non-vested restricted stock		(160	)		(5	)		(161	)		(2	)
Add shares issuable under fully vested restricted stock units		47			20			41			10
As adjusted - basic		34,618			28,494			34,111			28,460
Adjustments to reconcile to average common shares outstanding for purposes of computing diluted EPS:
Assumed conversion of convertible cumulative preferred stock		-			-			8,355			-
Assumed conversion of convertible preference stock		-			-			-			-
Assumed exercise of stock options		-			-			18			35
Assumed settlement of restricted stock units and performance share units		-			-			190			21
Assumed vesting of non-vested restricted stock		-			-			46			-
Diluted		34,618			28,494			42,720			28,516
Net income available to common shareholders
As reported - basic	$	(3,482	)	$	(3,058	)	$	7,708		$	174
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		-			-			1,454			-
Eliminate dividends and repurchase premium on convertible preference stock assumed converted		-			-			-			-
Diluted	$	(3,482	)	$	(3,058	)	$	9,162		$	174
Earnings per share from net income available to common shareholders
Basic	$	(0.10	)	$	(0.11	)	$	0.23		$	0.01
Diluted	$	(0.10	)	$	(0.11	)	$	0.21		$	0.01

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.

- 20 -

SEMCO ENERGY, INC.

CONDENSED NOTES TO THE UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

(Continued)

Note 6 - Business Segments (Continued)

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						Six Months Ended
	June 30,						June 30,
	2006			2005			2006			2005
	(in thousands)
Operating revenues
Gas distribution	$	95,664		$	94,083		$	364,428		$	317,531
Corporate and other		3,372			3,311			8,015			8,446
Reconciliation to consolidated financial statements
Intercompany eliminations (a)		(2,001	)		(1,761	)		(3,932	)		(3,784	)
Consolidated operating revenues	$	97,035		$	95,633		$	368,511		$	322,193
Operating income (loss)
Gas distribution	$	4,548		$	6,976		$	32,872		$	36,686
Corporate and other		15			167			725			600
Consolidated operating income	$	4,563		$	7,143		$	33,597		$	37,286
Depreciation and amortization
Gas distribution	$	6,888		$	6,793		$	13,704		$	13,416
Corporate and other		330			354			663			709
Consolidated depreciation and amortization	$	7,218		$	7,147		$	14,367		$	14,125

(a) Includes the elimination of intercompany gas distribution revenue of $55 and $108, respectively, for the three and six months ended June 30, 2006, and $53 and $103, respectively, for the three and six months ended June 30, 2005. Includes the elimination of intercompany corporate and other revenue of $1,946 and $3,824, respectively, for the three and six months ended June 30, 2006, and $1,708 and $3,681, respectively, for the three and six months ended June 30, 2005.

- 21 -

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						Six Months Ended
	June 30,						June 30,
	2006			2005			2006			2005
	(in thousands)
Components of net benefit cost
Service cost	$	1,043		$	744		$	1,960		$	1,461
Interest cost		1,285			1,238			2,581			2,449
Expected return on plan assets		(1,481	)		(1,358	)		(2,966	)		(2,717	)
Amortization of transition obligation		-			-			-			-
Amortization of prior service cost		41			27			68			54
Amortization of net loss		726			659			1,450			1,249
Net benefit cost	$	1,614		$	1,310		$	3,093		$	2,496
		Other Postretirement Benefits
	Three Months Ended						Six Months Ended
	June 30,						June 30,
		2006			2005			2006			2005
	(in thousands)
Components of net benefit cost
Service cost	$	128		$	110		$	291		$	233
Interest cost		488			460			975			931
Expected return on plan assets		(576	)		(541	)		(1,154	)		(1,082	)
Amortization of transition obligation		17			18			34			35
Amortization of prior service cost		(72	)		(72	)		(143	)		(143	)
Amortization of net loss		95			34			200			99
Amortization of regulatory asset		225			225			450			450
Net benefit cost	$	305		$	234		$	653		$	523

- 22 -

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 another site for only a brief period of time, the Company is subject to local, state and federal laws and regulations that require, among other things, the investigation and, if necessary, the remediation of contamination associated with these sites, irrespective of fault, legality of initial activity, or ownership, and which may impose liability for damage to natural resources. The Company has complied with the applicable Michigan Department of Environmental Quality (“MDEQ”) requirements, which require current landowners to mitigate unacceptable risks to human health from the byproducts of manufactured gas plant operations and to notify the MDEQ and adjacent property owners of potential contaminant migration. The Company is currently investigating these sites and anticipates conducting any necessary additional investigatory and 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 also is unable to estimate, at present, the costs that may be incurred in connection with the investigation and remediation of these sites or other potential environmental liabilities relating to these sites. In accordance with an MPSC accounting order, environmental assessment and remediation costs associated with certain manufactured gas plant sites 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 outstanding 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 appeals. During 2005, the Company made settlement offers to all taxing jurisdictions involved with 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 six-month periods ended June 30, 2006, by approximately $0.7 million and $0.8 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.

- 23 -

SEMCO ENERGY, INC.

CONDENSED NOTES TO THE UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

(Continued)

Note 8 - Commitments and Contingencies (Continued)

In October 2004, two Company subsidiaries (SEMCO Energy Services, Inc. and SEMCO Pipeline Company) were added as defendants in a putative class action lawsuit brought in federal district court in West Virginia alleging that the approximately 30 defendants named in the lawsuit engaged in gas marketing activities that violated state and federal anti-trust laws and otherwise tortiously interfered with the business opportunities of the plaintiffs from 1996 to the present. On October 4, 2005, the court granted a motion to dismiss filed by certain defendants, including the Company’s subsidiaries, as to federal anti-trust claims arising prior to October 25, 2000. On June 14, 2006, the court granted the Company’s motion for summary judgment on all remaining claims pending against the Company’s subsidiaries, on statute of limitations grounds. As a result of this ruling, SEMCO Energy Services, Inc. and SEMCO Pipeline Company have been dismissed, with prejudice, from the lawsuit.

In September 2002, the Company agreed to relocate its headquarters to Port Huron, Michigan, and leased part of a new office building in Port Huron from Acheson Ventures LLC (“Acheson”). As part of the transaction, Acheson agreed to sublease office space occupied by the Company in Farmington Hills, Michigan, and, beginning in February 2005, began to pay the Company’s Farmington Hills lease costs (approximately $36,000 per month until March 31, 2011, when the Farmington Hills lease expires), as agreed. In June 2005, Acheson ceased making these payments, ostensibly because the Company had breached its obligations by maintaining a satellite office in Troy, Michigan, for certain executives who also have offices in the Company’s Port Huron headquarters. The Company has filed an action in Michigan state court, seeking (i) damages for Acheson’s failure to pay the Company’s Farmington Hills lease costs, and (ii) a declaratory judgment that the Company has met its obligations to Acheson. 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.

To mitigate its damages, the Company has been paying the Farmington Hills lease costs and marketed the space to prospective subtenants, since the time Acheson ceased making the 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.

Note 9 - Regulatory Matters

On May 25, 2006, the Company filed a request with the MPSC seeking authority to increase the Company’s base rates for service by approximately $18.9 million, in total. The Company’s request covers approximately 248,000 MPSC Division residential, commercial, and industrial customers.

- 24 -

SEMCO ENERGY, INC.

CONDENSED NOTES TO THE UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

(Continued)

Note 9 - Regulatory Matters (Continued)

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; (ii) collection of LAUF gas costs in the 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 and one or more public evidentiary hearings. New base rates, if any, and the rate design ultimately approved by the MPSC may differ 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). 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 to consider this 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 asks the MPSC to approve the CCBC tariff, rates, charges and conditions of service that are currently in effect. 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.

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 through 2017. In November 2005, the Company submitted the gas supply contract to the RCA for its approval and hearings began in July 2006. During the hearings, Marathon declined to comply with an RCA discovery order on the grounds that the information sought was confidential and proprietary, and other parties made motions for sanctions. The hearings were recessed at the completion of the Company’s direct case. The administrative law judge indicated that the parties would be informed of the RCA’s further action by order. The Company is unable to predict what actions, if any, the RCA may take on the discovery issue or the effect of any such actions on the proceedings or the RCA’s disposition of the Marathon contract.

- 25 -

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 36.8% 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 six months ended June 30, 2006, and June 30, 2005:

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2006			2005			2006			2005
	(in thousands, except per share amounts)
Operating revenues	$	97,035		$	95,633		$	368,511		$	322,193
Operating expenses		92,472			88,490			334,914			284,907
Operating income	$	4,563		$	7,143		$	33,597		$	37,286
Other income (deductions)		(9,374	)		(10,606	)		(19,367	)		(21,154	)
Income tax (expense) benefit		1,835			1,350			(5,068	)		(5,749	)
Net income (loss)	$	(2,976	)	$	(2,113	)	$	9,162		$	10,383
Dividends on convertible cumulative preferred stock		506			945			1,454			1,097
Dividends and repurchase premium on convertible preference stock		-			-			-			9,112
Net income (loss) available to common shareholders	$	(3,482	)	$	(3,058	)	$	7,708		$	174
Earnings (loss) per share
Basic	$	(0.10	)	$	(0.11	)	$	0.23		$	0.01
Diluted	$	(0.10	)	$	(0.11	)	$	0.21		$	0.01
Average common shares outstanding
Basic		34,618			28,494			34,111			28,460
Diluted		34,618			28,494			42,720			28,516

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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 second quarter 2006 and second quarter 2005 results - The Company had a net loss available to common shareholders of $3.5 million (or $0.10 per share) for the three months ended June 30, 2006, compared to a net loss of $3.1 million (or $0.11 per share) for the three months ended June 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 increase in the net loss available to common shareholders for the second quarter of 2006 were: (i) a decrease in gas sales margin; (ii) an increase in operations and maintenance expenses; and (iii) a writedown of natural gas inventory at Ventures associated with the effort to mitigate the effect of the collection of MPSC Division LAUF gas expense in base rates discussed in Note 3 of the Condensed Notes to the Unaudited Consolidated Financial Statements in Part 1, Item 1 of this Form 10-Q. The impact of these items was partially offset by a decrease in financing-related costs and a decrease in property tax expense. The decrease in gas sales margin, which increased the second quarter 2006 net loss by approximately $1.1 million, was primarily due to 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. This sale accounted for approximately $0.8 million of the decrease in gas sales margin. Warmer temperatures, energy conservation by customers and an increase in LAUF natural gas expense also contributed to the decrease in gas sales margin during the second quarter of 2006. The increase in operations and maintenance expenses, which increased the net loss for the second quarter of 2006 by approximately $1.0 million, was primarily due to increases in employee benefit costs and uncollectible customer accounts. The writedown in value of natural gas inventory increased the 2006 net loss by approximately $0.3 million. The decrease in financing-related costs decreased the second quarter of 2006 net loss by approximately $1.1 million, when compared to the second quarter of 2005. The decrease in property tax expense, which decreased the net loss for the second quarter of 2006 by approximately $0.6 million, was primarily the result of taxing jurisdictions in Michigan accepting the Company’s settlement offers related to outstanding property tax appeals.

Comparison of six months ended June 30, 2006, and six months ended June 30, 2005, results - The Company’s net income available to common shareholders was $7.7 million (or $0.21 per share) for the six months ended June 30, 2006, compared to $0.2 million (or $0.01 per share) for the six months ended June 30, 2005. The primary factors that contributed to the increase in net income available to common shareholders when comparing the results for the six months ended June 30, 2006, to the results for the six months ended June 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 sales margin; (b) an increase in operations and maintenance expenses; and (c) the writedown of natural gas inventory discussed above. The decrease in financing-related costs increased net income for the six months ended June 30, 2006, by approximately $9.7 million when compared to the six months ended June 30, 2005. The primary item causing this decrease in financing-related costs was a payment of approximately $8.2 million included in the results for the first six months of 2005, which was associated with the repurchase of Convertible Preference Stock (“CPS”) and certain Common Stock warrants (the “Warrants”) in March 2005. The decrease in property tax expense was due primarily to the reasons discussed above and increased net income by approximately $0.7 million, when comparing results for the first six months of 2006 to the same period of 2005. The decrease in gas sales margin decreased net income for the first half of 2006 by approximately $1.2 million when compared to the first half of 2005. Gas sales margins decreased despite the positive impact of base rate increases in Michigan that were effective in April of 2005 and the addition of new customers in both Michigan and Alaska. The primary factors contributing to the decrease in 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, discussed above. The Company believes that energy conservation by customers has increased recently in response to increases in the market price of natural gas. The increase in operations and maintenance expense decreased net income by approximately $1.9 million during the six months ended June 30, 2006, when compared to the six months ended June 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.

- 27 -

 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

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 levels established earlier in December 2005. This recent 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 in comparison to average levels over the last five years. Despite the recent decrease in natural gas prices, future prices still remain relatively high for the upcoming 2006-2007 winter heating season. The Company believes that higher natural gas prices will persist and 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.

The Company has been addressing, and continues to address, the expected 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 the Company’s working capital requirements, (iii) evaluating customer consumption, and (iv) monitoring customer payment patterns in Michigan and Alaska. 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. 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.

 

- 28 -

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)

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. To illustrate this phenomenon, at June 30, 2005, the Company had $18.0 million of cash and cash equivalents and no short-term borrowings, while at June 30, 2006, the Company had $1.7 million in cash and cash equivalents and $31.2 million in short-term borrowings. 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 the higher level of short-term borrowings.

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. 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 six months ended June 30, 2006, and 2005.

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 closely 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 $2.0 million and $1.0 million for the six months ended June 30, 2006, and 2005, respectively. The $1.0 million increase in expense for uncollectible gas sales customer accounts for the six months ended June 30, 2006, when compared to the same period ended June 30, 2005, was primarily attributable to higher gas prices (resulting in higher customer bills), reduced government funding of low income heating programs and more stringent 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 0.55% at June 30, 2006, compared to 0.35% at June 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 increased cost of natural gas and related rate increases and other factors affecting customer payment patterns (including regulations governing service disconnections).

- 29 -

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 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 six months ended June 30, 2006, and 2005, were approximately 210 MMcf and 216 MMcf, respectively, or 0.7% and 0.6%, respectively, of volumes sold and transported in Michigan. The expense associated with LAUF gas in Michigan was $2.1 million and $1.4 million for the six months ended June 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.

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. The Company expects this conservation trend to continue as an era of higher and more volatile natural gas prices influences customer consumption patterns.

- 30 -

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 six-month periods ended June 30, 2006, and June 30, 2005:

	Six Months Ended
	June 30,
	2006			2005
Michigan
Degree days (DD) (a)
Actual		3,692			4,244
Normal (b)		4,225			4,183
Actual DD as a percent of normal DD		87.4	%		101.5	%
Percent by which actual DD differ from:
Normal DD (c)		(12.6	)%		1.5	%
Prior year actual DD (d)		(13.0	)%		0.4	%
Average gas consumption per customer (Mcf) (e)
Residential gas sales customers		53.9			65.5
Residential gas sales customers normalized (f)		61.7			64.5
Percent by which residential gas sales customers normalized differs from prior year residential gas sales customers normalized (g)		(4.3	)%		(3.1	)%
All gas sales customers		75.7			91.4
All gas sales customers normalized (f)		86.6			90.1
Percent by which all gas sales customers normalized differs from prior year all gas sales customers normalized (g)		(3.9	)%		(4.5	)%
Alaska
Degree days (DD) (a)
Actual		5,831			5,165
Normal (b)		5,500			5,584
Actual DD as a percent of normal DD		106.0	%		92.5	%
Percent by which actual DD differ from:
Normal DD (c)		6.0	%		(7.5	)%
Prior year actual DD (d)		12.9	%		(5.7	)%
Average gas consumption per customer (Mcf) (e)
Residential gas sales customers		98.8			89.2
Residential gas sales customers normalized (f)		93.2			96.4
Percent by which residential gas sales customers normalized differs from prior year residential gas sales customers normalized (g)		(3.3	)%		(3.1	)%
All gas sales customers		117.7			107.0
All gas sales customers normalized (f)		111.0			115.7
Percent by which all gas sales customers normalized differs from prior year all gas sales customers normalized (g)		(4.0	)%		(3.8	)%

(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 fifteen years. Beginning in 2006, normal degree days for the Company’s Alaska operations is determined using a ten-year average of degree days rather than a fifteen-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 one thousand 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.

- 31 -

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 12.6% warmer than normal during the first six months of 2006 and approximately 1.5% colder than normal during the first six months of 2005. In the Company’s Alaska service area, temperatures are estimated to have been approximately 6.0% colder than normal during the first six months of 2006 and approximately 7.5% warmer than normal during the first six months of 2005.

The Company has estimated that, in its Michigan service area, normalized average gas consumption during the first six months of 2006 for all gas sales customers decreased by approximately 3.9%, when compared to the first six months of 2005. In the Company’s Alaska service area, normalized average gas consumption during the first six months of 2006 for all gas sales customers decreased by an estimated 4.0%, when compared to the first six months of 2005.

The Company estimates that the combined variations from normal temperatures and decreases in normalized gas consumption decreased net income by approximately $3.1 million during the first six months of 2006 and approximately $1.9 million during the first six months of 2005.

Regulatory 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). 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.

Business Segment Overview

The Company has one reportable business segment known as the Gas Distribution Business. The Company’s other business segments that do not meet the quantitative thresholds required to be reportable business segments 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.

 

- 32 -

PART I - FINANCIAL INFORMATION - (Continued)

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

Business Segment Overview(Continued)

The Gas Distribution Business segment analysis and other discussions below provide additional information regarding variations in operating results when comparing the three- and six-month periods ended June 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.

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 six months ended June 30, 2006, and 2005, are not necessarily indicative of results for a full year.

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.”

Gas Sales Revenue - The Company’s gas sales revenue was $87.1 million and $343.6 million for the three and six months ended June 30, 2006, compared to $85.9 million and $297.6 for the three and six months ended June 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						Six Months Ended
	June 30,						June 30,
	2006			2005			2006			2005
	(dollars in thousands)
Gas sales revenues	$	87,122		$	85,884		$	343,605		$	297,616
Cost of gas sold		63,515			60,581			276,119			228,177
Gas sales margin	$	23,607		$	25,303		$	67,486		$	69,439
Gas transportation revenue		6,153			5,981			15,545			15,209
Other operating revenue		2,389			2,218			5,278			4,706
	$	32,149		$	33,502		$	88,309		$	89,354
Operation and maintenance		18,655			16,762			36,809			33,191
Depreciation and amortization		6,888			6,793			13,704			13,416
Property and other taxes		2,058			2,971			4,924			6,061
Operating income	$	4,548		$	6,976		$	32,872		$	36,686
Volumes of gas sold (MMcf)		9,417			9,393			36,048			38,338
Volumes of gas transported (MMcf)		12,752			13,237			27,275			27,578
Number of customers at end of period		408,826			403,731			408,826			403,731
Degree Days
Alaska		1,712			1,486			5,831			5,165
Michigan		750			833			3,692			4,244
Percent colder (warmer) than normal
Alaska		6.5	%		(7.4	)%		6.0	%		(7.5	)%
Michigan		(19.5	)%		(10.3	)%		(12.6	)%		1.5	%
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 2005, which increased gas sales margin for the three- and six-month periods ended June 30, 2005, by approximately $1.3 million and $1.4 million, respectively. There was no similar sale in the same periods in 2006.

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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)

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. A decrease in customer gas consumption during the three and six months ended June 30, 2006, decreased gas sales margin by approximately $0.3 million and $3.6 million, respectively, when compared to the same periods ended June 30, 2005. During the six months ended June 30, 2006, actual consumption per gas sales customer in Michigan decreased by approximately 17.2% when compared to the same period ending June 30, 2005. In Alaska, there was an increase in actual consumption per gas sales customer of approximately 10.0% when comparing the same periods. Normalized consumption per gas sales customer decreased by an estimated 3.9% in Michigan and an estimated 4.0% in Alaska, when comparing the six months ended June 30, 2006, to the six months ended June 30, 2005. The Company believes the decrease in normalized gas consumption per gas sales customer was due in large part to conservation prompted 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 six months of 2006 that were approximately 13.0% warmer than during the same period of 2005. This was partially offset by the impact of temperatures in Alaska during the first six months of 2006, which were approximately 12.9% 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 six-month period ended June 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 0.7% and 3.6%, respectively, when compared to the six-month period ended June 30, 2005. The additional customers increased gas sales margin for the three and six months ended June 30, 2006, by approximately $0.3 million and $1.1 million, respectively, when compared to the same periods ended June 30, 2005. Customers added to the Company’s Michigan operation as a result of the acquisition of Peninsular Gas Company contributed $0.2 million and $0.5 million, respectively, to gas sales margin during the three and six months ended June 30, 2006, when compared to the same periods ended June 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 this LAUF gas, including measurement errors and leaks. The annual LAUF gas volumes in Michigan have ranged from 0.5% to 1.4% of total gas volumes sold and transported in Michigan over the last ten years. An increase in LAUF gas expense decreased gas sales margin for both the three and six months ended June 30, 2006, by approximately $0.6 million when compared to the same periods ended June 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. For information regarding how the Company is attempting to manage the risk associated with changes in the underlying commodity cost and its impact on LAUF gas expense, refer to Note 3 of the Condensed Notes to the Consolidated Financial Statements in Part 1, Item 1 of this Form 10-Q and to the section of Management’s Discussion and Analysis titled “Corporate and Other.”

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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 remainder of the change in gas sales margin for the six months ended June 30, 2006, was due primarily to changes in rates and gas cost savings, as well as other miscellaneous factors. During the six months ended June 30, 2006, these factors increased gas sales margin by approximately $2.1 million when compared to the six months ended June 30, 2005. There was an increase in customer rates effective on March 31, 2005, for MPSC Division customers. The rate increase for MPSC Division customers was the result of a settlement agreement reached with 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.

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 and six months ended June 30, 2006, gas transportation revenue increased by $0.2 million and $0.3 million, respectively, when compared to the same periods ended June 30, 2005. The primary reason for these increases was an increase in transportation volumes to commercial customers as a result of colder weather in Alaska and an increase in commercial transportation customers. These increases were partially offset by warmer weather in Michigan and 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 three and six months ended June 30, 2006, when compared to the three and six months ended June 30, 2005, total gas transportation volumes were lower when comparing the same periods, by 485 MMcf and 303 MMcf, respectively. This 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 2006, but currently does not have sufficient natural gas under contract at an appropriate price to operate after that date. Transportation revenues to this customer totaled $2.0 million in 2005. Based upon volumes transported during the first six months of 2006 and estimates provided by the customer, transportation revenues to this facility are expected to total $1.2 million in 2006. The Company cannot predict the likely pattern of future operations at this plant, including whether the plant will ultimately close.

Other Operating Revenue - During thethree and six months ended June 30, 2006, other operating revenue increased by $0.2 million and $0.6 million, respectively, when compared to the same periods ended June 30, 2005. An increase in miscellaneous customer revenues partially offset by a decrease in pipeline management revenues were the primary reasons for the increases. The miscellaneous customer revenues include various service fees and late payment fees charged to customers and increased by approximately $0.2 million and $0.9 million for the three and six months ended June 30, 2006, respectively, when compared to the same periods ended June 30, 2005. 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. These revenues decreased by less than $0.1 million for the three months ended June 30, 2006, and by approximately $0.2 million for the six months ended June 30, 2006, when compared to the same periods ended June 30, 2005, primarily because of a pipeline construction project performed during the first quarter of 2005 in addition to NORSTAR’s routine pipeline management work.

- 36 -

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)

Operations and Maintenance Expenses -For the three and six months ended June 30, 2006, operations and maintenance (“O&M”) expenses increased by $1.9 million and $3.6 million, respectively, when compared to the same periods ended June 30, 2005. The $1.9 million change in O&M expenses between the second quarters of 2006 and 2005 was primarily impacted by changes in employee benefit costs and uncollectible customer accounts. These same items plus a charge associated with the sublease of office space that was the Company’s former headquarters were the primary items impacting the $3.6 million change in O&M expenses between the six-month periods ended June 30, 2006, and June 30, 2005.

Employee benefit costs primarily include pension expense, medical coverage expense (including retiree medical coverage), and incentive compensation. For the three and six months ended June 30, 2006, employee benefit costs increased by approximately $1.0 million and $1.9 million, respectively, when compared to the same periods ended June 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 additional share-based compensation.

Uncollectible customer accounts increased by approximately $0.5 million and $1.0 million for the three and six months ended June 30, 2006, respectively, when compared to the same periods ended June 30, 2005. These increases were primarily attributable to higher gas prices (resulting in higher customer bills), reduced government funding of low income heating programs and more stringent rules limiting the ability of the Gas Distribution Business to terminate service to delinquent customers.

The Company’s O&M expenses for the six months ended June 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 expenses between the three-month periods and between the six-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 six months ended June 30, 2006, by approximately $0.9 million and $1.1 million, respectively, when compared to the same periods ended June 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.

- 37 -

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)

Other Matters -In April 2006, the Company received a letter from Aurora Gas LLC (“Aurora”) regarding the gas supply contract for natural gas deliveries to ENSTAR from the Moquawkie natural gas field (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 deliveries effective October 1, 2006. If production is “Not Economic”, Aurora is entitled to suspend deliveries, subject to certain contract provisions. The Moquawkie Contract provides that Aurora will supply a portion of ENSTAR’s needs through 2014. Aurora is required to deliver up to 1.8 Bcf of natural gas in 2006. This requirement declines annually until the projected final year requirement of 0.2 Bcf in 2014. The total remaining commitment at the end of 2005 was approximately 10 Bcf. The Company responded to Aurora and, among other things, sought detailed information about Aurora’s claim that production under the Moquawkie Contract is “Not Economic.” The Company has met with Aurora, and the Company and Aurora have exchanged written statements of their legal positions. Aurora has provided some data that the Company is evaluating to determine whether production is “Not Economic.” The Company is considering alternative sources for the natural gas currently obtained under the Moquawkie Contract. The Company believes that alternative gas supplies would be supplied primarily by Union Oil Company of California (a subsidiary of Chevron Corporation) under its current contract with the Company.

The Company is in the process of replacing 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 is in the process of testing the new system and training employees on the new system and currently expects to put the system in service in October 2006.

Corporate and Other

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2006		2005		2006		2005
	(in thousands)
Operating revenues	$	3,372	$	3,311	$	8,015	$	8,446
Operating expenses		3,357		3,144		7,290		7,846
Operating income	$	15	$	167	$	725	$	600
The amounts in the above table include intercompany transactions.

- 38 -

PART I - FINANCIAL INFORMATION - (Continued)

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

Corporate and Other (Continued)

Operating Revenues- Corporate and Other reported operating revenue of $3.4 million and $8.0 million, respectively, for the three- and six-month periods ended June 30, 2006, compared to operating revenue of $3.3 million and $8.4 million, respectively, for the same periods ended June 30, 2005. The $0.1 million increase in revenues during the second quarter of 2006 when compared to the second quarter of 2005 was due to increases in both information technology (“IT”) services revenue and propane distribution revenue. The $0.4 million decrease in operating revenues when comparing the first six months of 2006 to the first six months of 2005 was due primarily to decreases in IT services revenue and propane distribution revenue. When comparing the six-month periods, IT revenues decreased by $0.3 million and propane revenues decreased by $0.1 million. IT revenues decreased because the Company generally has not been renewing contracts with non-affiliated customers due to ongoing efforts to focus the IT operations primarily on the Company’s IT needs, including the installation of a new Customer Information System. Propane revenues decreased because of warmer temperatures and conservation by customers during the winter heating season.

Operating Income - For the three- and six-month periods ended June 30, 2006, Corporate and Other reported operating income of approximately breakeven and $0.7 million, respectively, compared to operating income of $0.2 million and $0.6 million, respectively, for the same periods ended June 30, 2005. The $0.2 million decrease when comparing the second quarter of 2006 to the second quarter of 2005 was due primarily to a $0.5 million writedown of natural gas inventory based on market price for natural gas on June 30, 2006, offset partially by decreases in IT operating expenses. The $0.1 million increase in operating income during the six-month period ended June 30, 2006, when compared to the six-month period ended June 30, 2005, was due primarily to decreases in IT operating expenses and corporate professional fees, partially offset by the writedown of natural gas inventory discussed above and lower propane operating income due to warmer weather and customer conservation. Refer to Notes 1 and 3 of the Condensed Notes to the Unaudited Consolidated Financial Statements in Part 1, Item 1 of this Form 10-Q for information regarding the risk management reasons for purchasing natural gas inventory and the related accounting for the inventory and the forward sales of natural gas. Based on current forward natural gas prices and assuming the related storage is not interrupted, the Company expects this writedown of natural gas inventory to be offset by gains on the sale of the gas inventory during the second half of 2006 or the first quarter of 2007.

Other Income and Deductions

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2006			2005			2006			2005
	(in thousands)
Interest expense	$	(10,181	)	$	(10,860	)	$	(20,730	)	$	(21,936	)
Debt extinguishment costs		-			(366	)		-			(366	)
Other income		807			620			1,363			1,148
Total other income (deductions)	$	(9,374	)	$	(10,606	)	$	(19,367	)	$	(21,154	)

 

- 39 -

PART I - FINANCIAL INFORMATION - (Continued)

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

Other Income and Deductions (Continued)

Interest Expense - Interest expense for the three and six months ended June 30, 2006, decreased by $0.7 million and $1.2 million, respectively, when compared to the same periods ended June 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 levels of short-term bank borrowings under the Company’s Bank Credit Agreement and an increase in financing fees related to the Company’s Bank Credit Agreement. The higher level of short-term bank borrowings was due primarily to the impact of higher natural gas prices, which have 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 six months ended June 30, 2005, the Company’s Consolidated Statements of Operations reflect $0.4 million of debt extinguishment costs related to the redemption of $10.3 million of the Company’s 10.25% Subordinated Notes. 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 and six months ended June 30, 2006, increased by $0.2 million when compared to the same periods ended June 30, 2005. The increase was primarily the result of an increase in equity earnings from the Company’s investment in ERGSS, the Company’s gas storage partnership.

Income Taxes

Income tax expense (benefit) was $(1.8) million and $5.1 million, respectively, for the three and six months ended June 30, 2006, and $(1.4) million and $5.7 million, respectively, for the same periods ended June 30, 2005. The change in income taxes, when comparing one period to another, is due primarily to changes in earnings before income taxes.

- 40 -

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 the 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 $0.5 million and $1.5 million, respectively, for the three- and six-month periods ended June 30, 2006, and $0.9 million and $1.1 million, respectively, for the three- and six-month periods ended June 30, 2005. The decrease in dividends for the second quarter was due primarily to the impact of the Company’s repurchase and subsequent retirement of a portion of the Preferred Stock in the second quarter of 2006, 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. The increase in the dividends for the six months ended June 30, 2006, when compared to the same period ended June 30, 2005, is 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.

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 six months ended June 30, 2005. The Company’s Consolidated Statements of Operations for the six months ended June 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 six months ended June 30, 2006, and 2005:

	Six Months Ended
	June 30,
	2006			2005
	(in thousands)
Capital investments:
Property additions - gas distribution	$	(21,280	)	$	(15,289	)
Property additions - corporate and other		(120	)		(1,182	)
	$	(21,400	)	$	(16,471	)

The Company’s expenditures for property additions were approximately $21.4 million for the first six months of 2006. Expenditures for property additions during the remainder of 2006 are anticipated to be approximately $20.7 million.

- 41 -

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 $84.7 million for the six-month period ended June 30, 2006, compared to $78.5 million for the same period ended June 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 $61.6 million for the six-month period ended June 30, 2006, compared to $43.3 million for the same period ended June 30, 2005.

	Six Months Ended
	June 30,
	2006			2005
	(in thousands)
Cash provided by (used for) financing activities:
Issuance of common stock, net of expenses	$	43		$	545
Issuance of convertible cumulative preferred stock, net of expenses		-			66,397
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		(47,700	)		(39,300	)
Repayment of long-term debt		(92	)		(10,334	)
Payment of dividends on convertible cumulative preferred stock		(1,623	)		(583	)
Change in book overdrafts included in current liabilities		359			5
	$	(61,600	)	$	(43,270	)

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. 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. 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.

- 42 -

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 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 June 30, 2006, consisted of approximately 64.8% total debt (including current maturities and notes payable), 6.2% preferred stock and 29.0% 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 long-term debt during the remainder of 2006, the Company will continue to identify and, as appropriate, take advantage of market opportunities to do so as they arise.

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 June 30, 2006, the Company was utilizing $34.1 million of the borrowing capacity available under the Bank Credit Agreement, leaving approximately $85.9 million of the borrowing capacity unused. The $34.1 million of capacity being used consisted of $2.9 million of letters of credit and $31.2 million of borrowings. 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 June 30, 2006, the Company was in compliance with the Bank Credit Agreement covenants.

The Company’s Gas Distribution Business is seasonal in nature. During the winter heating season, higher volumes of gas are sold, resulting in peak profitability during the fourth and first quarters of the year. The Company’s cash flow and its corresponding use of its Bank Credit Agreement typically also follow a seasonal pattern. The Company uses funds available under the Bank Credit Agreement to finance, on a short-term basis, the variability and seasonality of its operating cash flow and working capital requirements. Typically, as the Company collects cash from winter heating sales in the latter part of the first quarter and the second quarter, it pays down the borrowings under the Bank Credit Agreement. During the summer months, it reduces its short-term borrowings under the Bank Credit Agreement, 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. 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 half of 2006, the Company’s volume of natural gas in storage has been higher 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 at June 30, 2006, when compared to June 30, 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. As a result of having higher levels of inventory at June 30, 2006, when compared to June 30, 2005, fewer volumes of natural gas will need to be purchased in the third and fourth quarters of 2006 than were purchased during the third and fourth quarters of 2005. Consequently, the Company’s short-term borrowing requirements for the purchase of natural gas are expected to be less than typical for the remainder of 2006. While the Company anticipates its short-term borrowings will peak near year-end, it also currently expects to have a significantly higher amount of unused short-term debt capacity when compared to December 31, 2005.

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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)

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.

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’’. 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 June 30, 2006. 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.

Changes in Internal Control Over Financial Reporting - During the quarter ended June 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.

On June 20, 2006, the Company issued nine 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.

For information on additional unregistered sales of equity securities, refer to the Company’s current reports on Form 8-K filed April 25, 2006 and May 26, 2006.

Item 3.Defaults Upon Senior Securities.

Not applicable.

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

At the May 22, 2006 Annual Meeting of Shareholders, the following nominees were elected as directors to hold office on the Board of Directors for a term of three years:

Name	Votes For	Votes Withheld
John T. Ferris	27,894,609	1,224,231
Paul F. Naughton	27,421,510	1,697,330
Edwina Rogers	28,177,173	941,667

The names of Directors whose term of office as a Director continued after the May 22, 2006 Annual Meeting of Shareholders are as follows:

John M. Albertine

Harvey I. Klein

George A. Schreiber, Jr.

Ben A. Stevens

Donald W. Thomason

John C. van Roden, Jr.

Item 5.Other Information.

Not applicable.

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PART II - OTHER INFORMATION (Continued)

Item 6.   Exhibits.

The following exhibits are filed herewith - (See page 49 for the Exhibit Index.)

Exhibits	Description
3.1	Articles of Incorporation of the Company, as restated June 25, 1999, and amendments thereto through May 28, 2004, including Certificate of Designation of 6% Series B Convertible Preference Stock filed March 19, 2004 (incorporated herein by reference to Exhibit 3.1 of the Company’s Form 10-Q for the quarter ended June 30, 2004, filed August 9, 2004).
3.1.1	Certificate of Designation of 5% Series B Convertible Cumulative Preferred Stock filed March 14, 2005 (incorporated herein by reference to Exhibit 3.1 to the Company's Form 8-K filed March 17, 2005).
3.2	Amended and Restated Bylaws of the Company, as amended through June 28, 2005 (incorporated herein by reference to Exhibit 3.2 of the Company's Form 8-K filed July 1, 2005).
10.36	Exchange Agreement between the Company and Linden Capital L.P. dated April 19, 2006 (incorporated herein by reference to Exhibit 10.1 of the Company’s Form 8-K filed April 25, 2006).
10.37	Exchange Agreement between the Company and Credit Suisse Securities (USA) LLC, dated May 22, 2006 (incorporated herein by reference to Exhibit 10.1 of the Company’s Form 8-K filed May 26, 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.

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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:  August 7, 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

Second Quarter 2006

Exhibits	Description
3.1	Articles of Incorporation of the Company, as restated June 25, 1999, and amendments thereto through May 28, 2004, including Certificate of Designation of 6% Series B Convertible Preference Stock filed March 19, 2004 (incorporated herein by reference to Exhibit 3.1 of the Company’s Form 10-Q for the quarter ended June 30, 2004, filed August 9, 2004).
3.1.1	Certificate of Designation of 5% Series B Convertible Cumulative Preferred Stock filed March 14, 2005 (incorporated herein by reference to Exhibit 3.1 to the Company's Form 8-K filed March 17, 2005).
3.2	Amended and Restated Bylaws of the Company, as amended through June 28, 2005 (incorporated herein by reference to Exhibit 3.2 of the Company's Form 8-K filed July 1, 2005).
10.36	Exchange Agreement between the Company and Linden Capital L.P. dated April 19, 2006 (incorporated herein by reference to Exhibit 10.1 of the Company’s Form 8-K filed April 25, 2006).
10.37	Exchange Agreement between the Company and Credit Suisse Securities (USA) LLC, dated May 22, 2006 (incorporated herein by reference to Exhibit 10.1 of the Company’s Form 8-K filed May 26, 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.

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