Semco Energy (SEN) 10-Q 2007 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, 2007
	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, 2007: 35,900,608

INDEX TO FORM 10-Q

For Quarter Ended June 30, 2007

			Page Number
INDEX TO FORM 10-Q			2
INFORMATION REGARDING 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	23
	Item 3.	Quantitative and Qualitative Disclosures About Market Risk	40
	Item 4.	Controls and Procedures	40
PART II - OTHER INFORMATION
	Item 1.	Legal Proceedings	41
	Item 1A.	Risk Factors	41
	Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	41
	Item 3.	Defaults upon Senior Securities	41
	Item 4.	Submission of Matters to a Vote of Security Holders	41
	Item 5.	Other Information	41
	Item 6.	Exhibits	42
SIGNATURES			43
EXHIBIT INDEX			44

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INFORMATION REGARDING FORWARD-LOOKING STATEMENTS

This Quarterly Report on 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 set forth 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 following:

·   the outcome of the pending transaction to sell the Company (the “Share Exchange”) and the effect on Company operations of restrictions placed on the Company pursuant to the terms of the Share Exchange;

·   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 regulations, 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 controls;

·   in the event that the Share Exchange is not consummated, 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 Quarterly Report on 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,
	2007			2006			2007			2006
	(In thousands, except per share amounts)
OPERATING REVENUES
Gas sales	$	110,609		$	87,122		$	407,288		$	343,605
Gas transportation		4,720			6,153			12,418			15,545
Other		4,342			3,760			12,096			9,361
		119,671			97,035			431,802			368,511
OPERATING EXPENSES
Cost of gas sold		83,890			63,515			326,218			276,119
Operations and maintenance		21,061			19,565			46,599			39,198
Depreciation and amortization		7,486			7,218			14,952			14,367
Property and other taxes		2,711			2,174			6,051			5,230
		115,148			92,472			393,820			334,914
OPERATING INCOME		4,523			4,563			37,982			33,597
OTHER INCOME (DEDUCTIONS)
Interest expense		(9,496	)		(10,181	)		(19,524	)		(20,730	)
Other		1,165			807			2,075			1,363
		(8,331	)		(9,374	)		(17,449	)		(19,367	)
INCOME (LOSS) BEFORE INCOME TAXES		(3,808	)		(4,811	)		20,533			14,230
INCOME TAX (EXPENSE) BENEFIT		1,504			1,835			(7,133	)		(5,068	)
NET INCOME (LOSS)		(2,304	)		(2,976	)		13,400			9,162
DIVIDENDS ON CONVERTIBLE CUMULATIVE PREFERRED STOCK		651			506			1,302			1,454
NET INCOME (LOSS) AVAILABLE TO COMMON SHAREHOLDERS	$	(2,955	)	$	(3,482	)	$	12,098		$	7,708
EARNINGS (LOSS) PER SHARE
Basic	$	(0.08	)	$	(0.10	)	$	0.34		$	0.23
Diluted	$	(0.08	)	$	(0.10	)	$	0.32		$	0.21
AVERAGE COMMON SHARES OUTSTANDING
Basic		35,523			34,618			35,488			34,111
Diluted		35,523			34,618			42,114			42,720
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,
	2007		2006
	(In thousands)
CURRENT ASSETS
Cash and cash equivalents	$	17,320	$	2,229
Restricted cash		3,740		3,627
Receivables, less allowances of $3,863 and $2,698		37,974		48,026
Accrued revenue		12,829		59,142
Gas in underground storage, at average cost		53,946		92,662
Deferred income taxes		11,149		8,690
Prepaid expenses		6,073		10,731
Materials and supplies, at average cost		6,035		5,258
Regulatory asset - gas charges recoverable from customers		-		2,949
Other		964		1,187
		150,030		234,501
PROPERTY, PLANT AND EQUIPMENT
Gas distribution		774,986		764,225
Corporate and other		39,669		39,400
		814,655		803,625
Less - accumulated depreciation		223,121		212,735
		591,534		590,890
DEFERRED CHARGES AND OTHER ASSETS
Goodwill		143,374		143,374
Regulatory assets		39,860		41,191
Unamortized debt expense		6,053		7,121
Other		14,182		14,494
		203,469		206,180
TOTAL ASSETS	$	945,033	$	1,031,571
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,
	2007			2006
	(In thousands, except for number of shares and par values)
CURRENT LIABILITIES
Notes payable	$	-		$	65,700
Accounts payable		36,335			63,901
Regulatory liability - amounts payable to customers		13,963			6,065
Customer advance payments		8,971			20,316
Accrued interest		4,570			4,734
Other		10,180			10,914
		74,019			171,630
DEFERRED CREDITS AND OTHER LIABILITIES
Regulatory liabilities		61,284			60,094
Deferred income taxes		51,948			43,008
Pension and other postretirement costs		27,579			26,496
Customer advances for construction		16,383			17,273
Other		7,909			7,729
		165,103			154,600
LONG-TERM DEBT		424,217			438,328
CONVERTIBLE CUMULATIVE PREFERRED STOCK
$1 par value; 500,000 shares authorized; 239,216 shares outstanding		45,776			45,670
COMMON SHAREHOLDERS' EQUITY
Common stock - $1 par value; 100,000,000 shares authorized; 35,778,562 and 35,457,706 shares outstanding		35,779			35,458
Capital surplus		252,701			250,643
Accumulated comprehensive income (loss)		(541	)		(639	)
Retained earnings (deficit)		(52,021	)		(64,119	)
		235,918			221,343
TOTAL LIABILITIES AND CAPITALIZATION	$	945,033		$	1,031,571
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,
		2007	2006
		(In thousands)
CASH FLOWS PROVIDED BY (USED FOR) OPERATING ACTIVITIES
	Net income	$    13,400	$     9,162
	Adjustments to reconcile net income to net cash provided by (used for) operating activities:
	Depreciation and amortization	14,951	14,367
	Amortization of debt costs and debt basis adjustments included in interest expense	1,738	1,703
	Deferred income taxes and amortization of investment tax credits	6,482	7,368
	Non-cash share-based compensation	1,191	913
	Changes in operating assets and liabilities and other:
	Receivables, net	10,052	33,370
	Accrued revenue	46,313	60,750
	Prepaid expenses	4,658	5,184
	Materials, supplies and gas in underground storage	37,939	7,005
	Regulatory asset - gas charges recoverable from customers	2,949	95
	Accounts payable	(27,567)	(44,900)
	Customer advances and amounts payable to customers	(4,335)	(15,116)
	Other	2,591	4,817
	NET CASH PROVIDED BY OPERATING ACTIVITIES	110,362	84,718
CASH FLOWS PROVIDED BY (USED FOR) INVESTING ACTIVITIES
	Property additions - gas distribution	(13,364)	(21,280)
	Property additions - corporate and other	(298)	(120)
	Property retirement costs, net of proceeds from property sales	(453)	(154)
	Equity contribution to gas storage partnership	-	(1,930)
	Changes in restricted cash	(113)	(2,047)
	NET CASH USED FOR INVESTING ACTIVITIES	(14,228)	(25,531)
CASH FLOWS PROVIDED BY (USED FOR) FINANCING ACTIVITIES
	Issuance of common stock, net of expenses	951	43
	Repurchase of convertible cumulative preferred stock, net of expenses	-	(12,587)
	Repayment of notes payable and payment of related expenses	(65,700)	(47,700)
	Repayment of long-term debt	(15,000)	(92)
	Payment of dividends on convertible cumulative preferred stock	(1,196)	(1,623)
	Change in book overdrafts included in current liabilities	(98)	359
	NET CASH USED FOR FINANCING ACTIVITIES	(81,043)	(61,600)
CASH AND CASH EQUIVALENTS
	Net increase	15,091	(2,413)
	Beginning of period	2,229	4,124
	End of period	$    17,320	$     1,711
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,
	2007			2006			2007		2006
	(In thousands)
NET INCOME (LOSS)	$	(2,304	)	$	(2,976	)	$	13,400	$	9,162
Valuation adjustment for marketable securities, net of income tax (expense) benefit of $(10), $4, $(15) and $(15)		17			(9	)		26		27
Unrealized derivative gain on an interest rate hedge from an investment in an affiliate		-			-			-		28
Unrealized derivative gain on interest rate hedge, net of income tax expense of $44, $0, $7 and $0		77			-			13		-
Amortization of net losses and net prior service costs associated with benefit plans, net of income tax expense of $18, $0, $35 and $0		30			-			60		-
COMPREHENSIVE INCOME (LOSS)	$	(2,180	)	$	(2,985	)	$	13,499	$	9,217
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 284,000 customers in Michigan and approximately 126,000 customers in Alaska. The Michigan operation is sometimes referred to as “SEMCO Gas” and the Alaska operation is sometimes referred to as “ENSTAR.” 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”) in Michigan and the Regulatory Commission of Alaska (“RCA”) in Alaska. Previously, the Company was also regulated in the Battle Creek, Michigan area by the City Commission of Battle Creek (“CCBC”). However, on June 26, 2007, the MPSC approved settlement agreements under which the MPSC assumed regulatory jurisdiction over the service area that had been regulated by the CCBC. For additional information on this transfer of regulatory jurisdiction from the CCBC to the MPSC, refer to Note 10.

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

References to the “Company” in the Condensed Notes to the Unaudited Consolidated Financial Statements 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 in the Company's 2006 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 are comprised of 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.

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.

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SEMCO ENERGY, INC.

CONDENSED NOTES TO THE UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

(Continued)

NOTE 1 - SIGNIFICANT ACCOUNTING POLICIES (Continued)

The 2007 annual impairment tests for the Company’s business units will be conducted during the third and fourth quarters of 2007. There were no changes in the carrying amount of goodwill for the six-month period ended June 30, 2007.

	Gas	Corporate
	Distribution	and	Total
	Segment	Other	Company
	(in thousands)
Balance as of December 31, 2006 and June 30, 2007	$     140,318	$         3,056	$     143,374

New Accounting Standards – In June 2006, the Financial Accounting Standards Board (“FASB”) issued Financial Interpretation Number 48, “Accounting for Uncertainty in Income Taxes — an interpretation of SFAS No. 109” (“FIN 48”). This interpretation clarifies the accounting for uncertainty in income taxes recognized in a company’s financial statements in accordance with SFAS 109, “Accounting for Income Taxes.” FIN 48 prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a position taken, or expected to be taken, in a tax return. FIN 48 also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition.

The Company’s adoption of FIN 48 on January 1, 2007, did not have a material impact on its consolidated financial position and results of operations. Upon the adoption of FIN 48 on January 1, 2007, and at June 30, 2007, the Company had approximately $1.1 million of gross unrecognized tax benefits associated with uncertain tax positions that, if recognized, would favorably affect the income tax provision when recorded. The Company does not believe the total amount of unrecognized tax benefits will either significantly increase or decrease within twelve months of the date of adoption of FIN 48. The statute of limitations has expired with respect to the relevant state and Federal income tax returns for all years through 2002.

It is the Company’s policy to account for interest and penalties associated with uncertain income tax positions as a component of income tax expense. As of June 30, 2007, no amounts were accrued for interest or penalties associated with uncertain income tax positions.

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

In February 2007, the FASB issued SFAS 159, “The Fair Value Option for Financial Assets and Financial Liabilities — Including an amendment of FASB Statement No. 115.” SFAS 159 permits a company to choose to measure many financial instruments and certain other items at fair value. If the Company chooses to elect the fair value option for an item, the Company would recognize unrealized gains and losses associated with changes in the fair value of the item over time. SFAS 159 will also require disclosures for items for which the fair value option has been elected. SFAS 159 will be effective for the Company on January 1, 2008. The Company is currently evaluating the impact of SFAS 159 on its choosing to elect the fair value option for any of its financial instruments or other items on its financial position, cash flows, and results of operations.

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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 facility, which expires on September 15, 2008 (the “Bank Credit Agreement”). Interest under the terms of the Bank Credit Agreement is at variable rates, which are based on LIBOR or prime lending rates, plus applicable margins. LIBOR-based borrowings are permitted for periods ranging from two weeks to one, two, three or six months. At June 30, 2007, the Company was utilizing $0.2 million of the borrowing capacity available under the Bank Credit Agreement, leaving approximately $119.8 million of the borrowing capacity unused. The $0.2 million of capacity being used represented letters of credit. The amount borrowed under the Bank Credit Agreement will change from time to time and reflect the Company’s then-current working capital needs at any particular point in time as well as the rates charged under the Bank Credit Agreement and Lines of Credit (as defined below), if available.

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, 2007, the required minimum net worth was $229.7 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, the Lines of Credit 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 the Company’s business, results of operation, liquidity and financial condition.

The Company has four unsecured discretionary bank lines of credit (“Lines of Credit”) totaling $52.5 million consisting of:

Unsecured Discretionary Lines of Credit
Effective Date	Expiration Date	Amount Available
		(millions)
October 13, 2006	October 1, 2007	$	15.0
November 16, 2006	November 16, 2007	$	7.5
January 5, 2007	October 31, 2007	$	15.0
May 1, 2007	October 1, 2007	$	15.0

The banks are not obligated to make any advances under these Lines of Credit and may at any time, without notice, in their sole and absolute discretion, refuse to make advances to the Company. Interest paid under the Lines of Credit is at variable rates, which are based upon prime lending rates or rates quoted by the banks. The Company anticipates that, under these arrangements with various lenders, its total outstanding advances under the current Lines of Credit, collectively, will not exceed $15 million at the end of each quarter. At June 30, 2007, the Company was not utilizing any of the borrowing capacity available under these Lines of Credit. The amounts borrowed under the Lines of Credit will change from time to time and reflect the Company’s then-current capital needs at any particular point in time as well as the interest rates charged under the Bank Credit Agreement and Lines of Credit, if available.

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SEMCO ENERGY, INC.

CONDENSED NOTES TO THE UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

(Continued)

NOTE 2 - SHORT-TERM BORROWINGS AND CAPITALIZATION (Continued)

Long Term Debt – On October 31, 2006, the Company entered into a bank term loan agreement with Union Bank of California in the amount of $55 million (the “Bank Term Loan”). On April 5, 2007 and May 29, 2007, the Company repaid $10 million and $5 million, respectively, of the Bank Term Loan, leaving $40 million outstanding at June 30, 2007. For further information on the Bank Term Loan, refer to Note 4 of the Notes to the Consolidated Financial Statements in Part II, Item 8 of the Company’s 2006 Annual Report on Form 10-K.

5% Series B Convertible Cumulative Preferred Stock – Holders of shares of the Company’s 5% Series B 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. On May 15, 2007, the Company paid dividends on its Preferred Stock totaling approximately $0.6 million, or $2.50 per share.  The Company’s Board of Directors (the “Board”) has also declared a dividend payable on August 15, 2007, at a rate of $2.50 per share, to Preferred Stock holders of record on August 1, 2007. For further information on the Preferred Stock, refer to Note 4 of the Notes to the Consolidated Financial Statements in Part II, Item 8 of the Company’s 2006 Annual Report on Form 10-K.

Common Shareholder’s Equity – During the three and six months ended June 30, 2007, the Company issued no shares and 4,043 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. The DRIP was terminated on June 29, 2007 in connection with the pending Share Exchange, and no new shares of Common Stock will be issued through the DRIP in the future. Also during the three and six months ended June 30, 2007, the Company issued 30,842 shares and 70,204 shares, respectively, of its Common Stock to certain of the Company's employee benefit plans.

During the three and six months ended June 30, 2007, 63,856 shares and 81,268 shares, respectively, of Common Stock were delivered to Company executives to satisfy awards made under the Company’s 2004 Stock Award and Incentive Plan (the “2004 Plan”). For additional information on these awards, refer to Note 4. In addition, during the three and six months ended June 30, 2007, 138,834 shares and 142,834 shares of Common Stock were issued upon the exercise of options to purchase the Company’s Common stock.

NOTE 3 - RISK MANAGEMENT ACTIVITIES AND DERIVATIVE TRANSACTIONS

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

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SEMCO ENERGY, INC.

CONDENSED NOTES TO THE UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

(Continued)

NOTE 3 - RISK MANAGEMENT ACTIVITIES AND DERIVATIVE TRANSACTIONS (Continued)

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

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, 2007, included a liability of $1.0 million and a decrease in long-term debt of $1.0 million associated with this interest rate swap.

The Company may also enter into floating-to-fixed interest rate swaps, from time to time, in order to maintain its desired mix of fixed-rate and floating-rate debt. These swaps are designated as cash flow 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. The Company entered into two such interest rate swaps, each with a notional amount of $20 million, in November 2006. These swaps were entered into in order to hedge the LIBOR component of the interest payments for a one- and two-year period on $40 million of the Company’s Bank Term Loan. These swap agreements, which became effective February 27, 2007, qualify under the provisions of SFAS 133, as a cash flow hedge. For cash flow hedges, the effective portion of gains and losses on derivative transactions is reported as a component of other comprehensive income. Gains and losses related to hedge ineffectiveness for outstanding derivatives is computed on a quarterly basis and included in interest expense. During the six-month period ended June 30, 2007, there was no amount of ineffectiveness reported in earnings. As of June 30, 2007, the Company’s Consolidated Statement of Financial Position included an asset of $0.1 million (representing the fair value of these swaps), with a like amount, net of income taxes, included in accumulated comprehensive income. For further information on the cash flow interest rate swaps entered into in November 2006 and the Company’s Bank Term Loan, refer to Note 4 of the Notes to the Consolidated Financial Statements in Part II, Item 8 of the Company’s 2006 Annual Report on Form 10-K.

- 13 -

SEMCO ENERGY, INC.

CONDENSED NOTES TO THE UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

(Continued)

NOTE 4 – SHARE-BASED COMPENSATION

The Company grants performance share units (“PSUs”) to certain of its employees under the 2004 Plan. During the first quarter of 2007, the Company granted 234,610 PSUs. For information regarding terms of the Company’s PSUs, refer to Note 9 of the Notes to the Consolidated Financial Statements in Part II, Item 8 of the Company’s 2006 Annual Report on Form 10-K.

In March 2007, the Board certified that performance goals associated with 25,000 PSUs granted to an executive in March of 2005 had been met at target. Upon certification, 17,412 shares of Common Stock were issued to the executive and the remaining 7,588 shares were withheld to cover income tax withholding requirements.

During 2004 and 2005, the Company issued 114,728 restricted stock units (“RSUs”) to certain Company executives under its 2004 Plan. Each RSU is equivalent to one share of Company Common Stock. 10,000 of the RSUs issued in 2004 were forfeited because the executive to whom the RSUs were issued is no longer employed by the Company. Of the RSUs issued in 2005, 14,728 vest in full on the three-year anniversary of issuance as long as the executive who received the RSUs remains employed on the vesting date. The remaining 90,000 outstanding RSUs vested at different dates over the period from issuance to March 31, 2007. For information regarding terms of the Company’s RSUs, refer to Note 9 of the Notes to the Consolidated Financial Statements in Part II, Item 8 of the Company’s 2006 Annual Report on Form 10-K.

In April 2007, the Board certified that service and performance goals associated with 90,000 RSUs were attained as of March 31, 2007. In June 2007, 63,856 shares of Common Stock were delivered to certain executives and the remaining 26,144 shares were withheld to cover income tax withholding requirements.

The Company grants shares of restricted Common Stock to non-employee Directors under the 2004 Plan as part of the compensation paid to Directors. On June 7, 2007, the Company granted 22,500 shares of restricted Common Stock to its non-employee Directors. For information regarding terms under which restricted Common Stock is vested, refer to Note 9 of the Notes to the Consolidated Financial Statements in Part II, Item 8 of the Company’s 2006 Annual Report on Form 10-K.

NOTE 5 – EARNINGS PER SHARE

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

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

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SEMCO ENERGY, INC.

CONDENSED NOTES TO THE UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

(Continued)

NOTE 5 - EARNINGS PER SHARE (Continued)

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2007		2006		2007		2006
	(in thousands)
Potential dilutive impact on average common shares outstanding when calculating diluted earnings per share
Assumed conversion of convertible cumulative preferred stock		6,254		7,569		6,254		8,355
Assumed exercise of stock options		159		18		119		18
Assumed settlement of restricted stock units and performance share units		190		186		207		190
Assumed vesting of non-vested restricted stock		51		47		46		46
Potential income statement adjustments when calculating diluted earnings per share
Eliminate dividends on convertible cumulative preferred stock assumed converted	$	651	$	506	$	1,302	$	1,454

The following table outlines the computations of basic and diluted EPS for the three and six months ended June 30, 2007, and 2006. The potential adjustments indicated in the previous table are not included in the following computations of diluted EPS if their impact for a given period is anti-dilutive when compared to basic EPS for the period:

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2007			2006			2007			2006
	(in thousands, except per share amounts)
Average common shares outstanding
Issued		35,570			34,731			35,528			34,231
Adjustments to reconcile to average common shares outstanding for purposes of computing basic EPS:
Subtract non-vested restricted stock		(101	)		(160	)		(100	)		(161	)
Add shares issuable under fully vested restricted stock units		52			47			58			41
Add shares issuable under deferred compensation stock units		2			-			2			-
As adjusted - basic		35,523			34,618			35,488			34,111
Adjustments to reconcile to average common shares outstanding for purposes of computing diluted EPS:
Assumed conversion of convertible cumulative preferred stock		-			-			6,254			8,355
Assumed exercise of stock options		-			-			119			18
Assumed settlement of restricted stock units and performance share units		-			-			207			190
Assumed vesting of non-vested restricted stock		-			-			46			46
Diluted		35,523			34,618			42,114			42,720
Net income (loss) available to common shareholders
As reported - basic	$	(2,955	)	$	(3,482	)	$	12,098		$	7,708
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		-			-			1,302			1,454
Diluted	$	(2,955	)	$	(3,482	)	$	13,400		$	9,162
Earnings per share from net income (loss)available to common shareholders
Basic	$	(0.08	)	$	(0.10	)	$	0.34		$	0.23
Diluted	$	(0.08	)	$	(0.10	)	$	0.32		$	0.21

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SEMCO ENERGY, INC.

CONDENSED NOTES TO THE UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

(Continued)

NOTE 6 - BUSINESS SEGMENTS

The Company has one reportable business segment known as the Gas Distribution Business. Under SFAS 131, 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 categorywith 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 2006 Annual Report on Form 10-K.

The accounting policies of the Company’s business segments are the same as those described in Notes 1 and 11 of the Notes to the Consolidated Financial Statements in Part II, Item 8 of the Company’s 2006 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,
	2007			2006			2007			2006
	(in thousands)
Operating revenues
Gas distribution	$	118,160		$	95,664		$	424,847		$	364,428
Corporate and other		3,265			3,372			10,762			8,015
Reconciliation to consolidated financial statements
Intercompany eliminations  (a)		(1,754	)		(2,001	)		(3,807	)		(3,932	)
Consolidated operating revenues	$	119,671		$	97,035		$	431,802		$	368,511
Operating income (loss)
Gas distribution	$	4,726		$	4,548		$	39,921		$	32,872
Corporate and other		(203	)		15			(1,939	)		725
Consolidated operating income	$	4,523		$	4,563		$	37,982		$	33,597
Depreciation and amortization
Gas distribution	$	7,179		$	6,888		$	14,332		$	13,704
Corporate and other		307			330			620			663
Consolidated depreciation and amortization	$	7,486		$	7,218		$	14,952		$	14,367

__________

(a) Includes the elimination of intercompany gas distribution revenue of $58 and $114, respectively, for the three and six months ended June 30, 2007, and $55 and $108, respectively, for the three and six months ended June 30, 2006. Includes the elimination of intercompany corporate and other revenue of $1,696 and $3,693, respectively, for the three and six months ended June 30, 2007, and $1,946 and $3,824, respectively, for the three and six months ended June 30, 2006.

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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,
	2007			2006			2007			2006
	(in thousands)
Components of net benefit cost
Service cost	$	999		$	1,043		$	1,982		$	1,960
Interest cost		1,441			1,285			2,848			2,581
Expected return on plan assets		(1,572	)		(1,481	)		(3,141	)		(2,966	)
Amortization of prior service cost		34			41			68			68
Amortization of net loss		646			726			1,194			1,450
Net benefit cost	$	1,548		$	1,614		$	2,951		$	3,093
	Other Postretirement Benefits
	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2007			2006			2007			2006
	(in thousands)
Components of net benefit cost
Service cost	$	164		$	128		$	341		$	291
Interest cost		540			488			1,111			975
Expected return on plan assets		(600	)		(576	)		(1,199	)		(1,154	)
Amortization of transition obligation		-			17			-			34
Amortization of prior service credit		(108	)		(72	)		(216	)		(143	)
Amortization of net loss		131			95			285			200
Amortization of regulatory asset		225			225			450			450
Net benefit cost	$	352		$	305		$	772		$	653

- 17 -

SEMCO ENERGY, INC.

CONDENSED NOTES TO THE UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

(Continued)

NOTE 8 - COMMITMENTS AND CONTINGENCIES

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

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

The Company accrues for costs associated with environmental investigation and remediation obligations when such costs are probable and reasonably estimable. Accruals for estimated costs for environmental remediation obligations are generally recognized no later than the completion of the Company’s Remedial Action Plan (“RAP”) for a site. Such accruals are expected to be adjusted as further information becomes available or circumstances change. At three of the Company’s sites, the Company has begun efforts to determine the extent of remediation, if any, that must be performed, with the expectation of completing and submitting an RAP for each of the sites to the MDEQ. As a result of investigational work performed to date, the Company’s Consolidated Statements of Financial Position include an accrual and a corresponding regulatory asset in the amount of $1.6 million at June 30, 2007, for estimated environmental investigation and remediation costs that it believes are probable at these three sites. The Company has not discounted this accrual to its present value. The accrued costs are expected to be paid out over the next three years.

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

- 18 -

SEMCO ENERGY, INC.

CONDENSED NOTES TO THE UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

(Continued)

NOTE 8 - COMMITMENTS AND CONTINGENCIES (Continued)

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

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

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

In September 2002, the Company agreed to relocate its headquarters to Port Huron, Michigan, and leased part of a new office building in Port Huron from Acheson Ventures LLC (“Acheson”). As part of the transaction, Acheson agreed to sublease office space occupied by the Company in Farmington Hills, Michigan, and, beginning in February 2005, began to pay the Company’s Farmington Hills lease costs (approximately $36,000/month until March 31, 2011, when the Farmington Hills lease expires), as agreed. In June 2005, Acheson ceased making these payments, ostensibly because the Company had allegedly breached its obligations by maintaining a satellite office in Troy, Michigan, for certain executives who also have offices in the Company’s Port Huron headquarters. The Company 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. 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 St. Clair County, Michigan. The Company made filings to answer Acheson’s counter-claims, denying any liability to Acheson and opposing a change of venue. The court subsequently ruled that venue for this case was properly laid in Oakland County, Michigan. Pre-trial activities in this case, including Acheson’s motion renewing its venue change request, are underway. The court ruled on February 21, 2007, that the venue was proper in St. Clair County, Michigan, essentially overturning its earlier venue ruling. The Company has appealed this recent venue ruling.

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

- 19 -

SEMCO ENERGY, INC.

CONDENSED NOTES TO THE UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

(Continued)

NOTE 8 - COMMITMENTS AND CONTINGENCIES (Continued)

In April 2006, Aurora Gas LLC (“Aurora Gas”) gave the Company notice of the suspension of gas deliveries, and subsequently suspended deliveries, to the Company’s Alaska Pipeline Company subsidiary (which, in turn, are delivered to the Company’s ENSTAR Division for resale to its customers in Alaska) under the gas supply contract between the Company and Aurora Gas pursuant to which Aurora Gas sells natural gas to the Company from the Moquawkie natural gas field (the “Moquawkie Contract”). Aurora Gas asserted that it was permitted to take these actions because production has become “Not Economic,” as that term is defined in the Moquawkie Contract. The Company disagrees with Aurora Gas’s contentions, and attempts to resolve this matter informally were unsuccessful. The Company filed suit against Aurora Gas and an affiliate in Alaska state court asserting, among other things, a breach of contract claim. Aurora Gas has defended against the Company’s claims in this lawsuit by insisting upon its right to suspend gas deliveries. Pre-trial activities in this case are underway. For further information concerning this dispute with Aurora Gas and related rate recovery implications, refer to Note 2 of the Notes to the Consolidated Financial Statements in Part II, Item 8 of the Company’s 2006 Annual Report on Form 10-K.

On April 16, 2007, a purported shareholder class action lawsuit, captioned Advantage Investors v. John T. Ferris et al., was filed in the Michigan Circuit Court of the County of St. Clair, against the Company, each of its Directors, and Cap Rock (as defined in Note 9 below). The complaint alleged, among other things, that the Directors were self-interested and breached their fiduciary duties to the shareholders of the Company in approving the Share Exchange. The complaint also alleged that Cap Rock had aided the alleged breaches of fiduciary duty by the Directors. The complaint sought a declaration that the action was properly maintainable as a class action and that the plaintiff was the proper class representative, a declaration that the defendants had breached their fiduciary duties or aided such breaches, and compensatory and/or rescissory damages, reasonable costs and attorneys’ fees and other remedies. This lawsuit has been settled, subject to Court approval of the settlement and the completion of various procedural steps (such as notifying shareholders of the settlement and their rights). For its part, the Company agreed to make, and subsequently made, certain additional disclosures in the proxy solicitation materials sent to shareholders in connection with the special meeting to consider the Share Exchange. Procedures related to Court approval of the settlement and other settlement-related procedural steps are underway.

NOTE 9 - PENDING SALE OF THE COMPANY

As previously reported, on February 22, 2007, the Company entered into an Agreement and Plan of Share Exchange (the “Exchange Agreement”) by and among the Company, Cap Rock Holding Corporation (“Cap Rock”) and Semco Holding Corporation, a direct wholly-owned subsidiary of Cap Rock (“Parent”), under which Parent will acquire all the outstanding Common Stock and Preferred Stock of the Company. Pursuant to the terms of the Exchange Agreement, each issued and outstanding share of Common Stock and Preferred Stock of the Company will be transferred to Parent. The Common Stock will be transferred for the right to receive $8.15 in cash per share, without interest, and the Preferred Stock will be transferred for the right to receive approximately $213.07 in cash per share plus a make-whole premium to be calculated at closing, without interest, in each case on the terms and subject to the conditions set forth in the Exchange Agreement. The Board, upon the unanimous recommendation of its Finance Committee (which is comprised entirely of independent directors), approved the Exchange Agreement and recommended that the holders of the Company’s Common Stock approve the Share Exchange at a special meeting that was held on June 7, 2007, as discussed below.

- 20 -

SEMCO ENERGY, INC.

CONDENSED NOTES TO THE UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

(Continued)

NOTE 9 - PENDING SALE OF THE COMPANY (Continued)

Consummation of the Share Exchange is not subject to a financing condition, but is subject to various other conditions, including approval of the Share Exchange by the holders of the Company’s Common Stock, approval by the RCA, expiration or termination of applicable waiting periods under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended (the “HSR Act”), and satisfaction of other customary closing conditions. On April 27, 2007, the Federal Trade Commission (the “FTC”) granted early termination of the waiting period under the HSR Act. On June 7, 2007, at a special meeting of the Company’s shareholders, the holders of the Company’s Common Stock approved the Exchange Agreement. Refer to Note 10 for information regarding the status of regulatory approvals required in connection with the Share Exchange.

Also in connection with the Exchange Agreement, on February 22, 2007, the Company executed an amendment to its rights agreement, dated as of April 15, 1997, as amended, with National City Bank, as rights agent, (the “Rights Agreement”) for the purpose of amending the Rights Agreement to render it inapplicable to the Exchange Agreement, the Share Exchange and the other transactions contemplated thereby. The amendment provided that the execution of, and the consummation of the transactions contemplated by, the Exchange Agreement will not cause (1) Cap Rock or Parent or any of their affiliates or associates to be deemed an acquiring person, or (2) a distribution date, share acquisition date or triggering event to be deemed to have occurred. The Rights Agreement expired by its terms on April 15, 2007.

NOTE 10 - REGULATORY MATTERS

In order to acquire a controlling interest in the Company’s ENSTAR division and Alaska Pipeline Company subsidiary, which are public utilities in Alaska, an application must be filed in the form prescribed by the RCA for authority to acquire a controlling interest in these entities.  This application was filed by Cap Rock and the Company with the RCA on April 9, 2007. The RCA has established a procedural schedule to consider the application (including hearings scheduled to be held in early-September 2007) and has provided individuals or entities with an interest in the proceeding an opportunity to comment on the application and intervene in the proceeding. Some proceedings are resolved by stipulation without an evidentiary hearing; however, in most circumstances, the RCA will convene an evidentiary hearing before a decision is made by the RCA. The RCA is required to act on an application to acquire a controlling interest in a utility within six months of the filing of a completed application, subject to a one-time extension of the deadline for good cause shown (not to exceed 90 days) or upon agreement of the parties to the proceeding. The Exchange Agreement provides as a condition to closing that such final order issued by the RCA must not, among other things, impose substantial or burdensome conditions.

Under the HSR Act and the rules promulgated thereunder by the FTC, the Share Exchange may not be completed until notification and report forms have been filed with the FTC and the Antitrust Division of the Department of Justice and the applicable waiting period has expired. On April 17, 2007, the Company and Parent filed notification and report forms under the HSR Act with the FTC and the Antitrust Division of the Department of Justice. On April 27, 2007, the FTC granted early termination of the waiting period under the HSR Act.

- 21 -

SEMCO ENERGY, INC.

CONDENSED NOTES TO THE UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

(Continued)

NOTE 10 - REGULATORY MATTERS (Continued)

The Company’s annual Gas Cost Recovery (“GCR”) reconciliation case for the period ended March 31, 2006, is currently pending before the MPSC. In such cases, the MPSC assesses the Company’s gas procurement practices for gas purchased for sale to customers in that portion of the Company’s Michigan service area regulated by the MPSC. Interveners in the case have proposed $5.6 million in gas cost disallowances. The Company believes that it acted reasonably with respect to its gas purchases for the GCR period under review and therefore does not believe that any disallowances are appropriate. While the Company does not believe that any gas cost disallowances are appropriate, it cannot make any assurances as to whether the MPSC will disallow any costs at issue in this case.

In May 2006, the Company and the CCBC filed a joint application with the MPSC requesting that the MPSC assume jurisdiction over the service area currently regulated by the CCBC. The joint application asked the MPSC to approve the CCBC tariff, rates, charges and conditions of service that were currently in effect in the areas then regulated by the CCBC. In October 2006, the Company and the CCBC submitted an amended joint application to address certain rate and procedural issues. The amended joint application provided that the Company would file a GCR gas purchase plan similar to the GCR gas purchase plan filed annually with the MPSC for the Company’s gas distribution service area regulated by the MPSC and a GCR tariff. In December 2006, the Company filed for approval of a GCR clause and for approval of a GCR gas purchase plan. In June 2007, the parties to the proceedings reached a settlement and filed settlement agreements with the MPSC. The MPSC subsequently approved the settlement agreements under which the MPSC assumed jurisdiction over the service area that had been regulated by the CCBC effective with the first billing cycle in July 2007, approved the implementation of a GCR clause and approved the implementation of the filed GCR gas purchase plan.  In June 2007, a petition for rehearing was filed by a group purporting to represent Battle Creek area customers on the jurisdiction change from the CCBC to the MPSC. The Company and the CCBC have opposed the petition for rehearing, and the Company believes the petition is without merit. The Company is unable to predict, however, when the MPSC will act on this filing or what the outcome might be.

NOTE 11 - SUBSEQUENT EVENTS

On July 12, 2007, a new tax called the Michigan Business Tax (“MBT”) was signed into law in Michigan. The MBT will be imposed on businesses operating in Michigan beginning on January 1, 2008.  The MBT consists of two new taxes: (i) a modified gross receipts tax of 0.8%; and (ii) a net income tax of 4.95%.  The MBT is a form of income tax and is therefore subject to SFAS 109, “Accounting for Income Taxes.”  The MBT will replace Michigan’s current Single Business Tax (“SBT”), which is a “value added” tax, and therefore is not subject to SFAS 109. The Company’s SBT expense is reflected in its Consolidated Statements of Operations under the caption “Property and Other Taxes.” The MBT expense will be reflected under the caption “Income Taxes.”

SFAS 109 requires an annual measurement of deferred tax assets and deferred tax liabilities based upon the estimated future tax effects of temporary differences and carry-forwards.  Under SFAS 109, any additional deferred tax assets and liabilities required as a result of initial accounting for the MBT must be recorded in the third quarter of 2007, because that is when the MBT was signed into law. There are also legislative amendments that may be proposed shortly that could impact the initial amount of deferred tax assets and liabilities recorded as a result of the MBT. The initial recording of deferred taxes related to the MBT will be a non-cash event and will therefore not have a material effect on the Company’s cash flows. The Company is currently in the process of evaluating the potential impact of the MBT, including the related regulatory treatment, on its financial position and results of operations.

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PART I - FINANCIAL INFORMATION - (Continued)

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

OVERVIEW AND OTHER INFORMATION

Summary of Results of Operations - The discussions in this section are summarized and intended to provide an overview of the results of Company operations. In most instances, the items discussed here are covered in greater detail in later sections of Management’s Discussion and Analysis.  Any variances in results in this summary are quantified on an after-tax basis. The Company uses an effective income tax rate of 36.9% to estimate these after-tax amounts. All references to EPS in Management’s Discussion and Analysis are on a fully diluted basis. For information related to the calculation of diluted EPS, refer to Note 5 of the Condensed Notes to the Unaudited Consolidated Financial Statements in Part 1, Item 1 of this Quarterly Report on Form 10-Q. The following table summarizes the Company’s operating results for the three and six months ended June 30, 2007, and June 30, 2006:

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2007			2006			2007			2006
	(in thousands, except per share amounts)
Operating revenues	$	119,671		$	97,035		$	431,802		$	368,511
Operating expenses		115,148			92,472			393,820			334,914
Operating income	$	4,523		$	4,563		$	37,982		$	33,597
Other income (deductions)		(8,331	)		(9,374	)		(17,449	)		(19,367	)
Income tax expense		1,504			1,835			(7,133	)		(5,068	)
Net income (loss)	$	(2,304	)	$	(2,976	)	$	13,400		$	9,162
Dividends on convertible cumulative preferred stock		651			506			1,302			1,454
Net income (loss) available to common shareholders	$	(2,955	)	$	(3,482	)	$	12,098		$	7,708
Earnings (loss) per share
Basic	$	(0.08	)	$	(0.10	)	$	0.34		$	0.23
Diluted	$	(0.08	)	$	(0.10	)	$	0.32		$	0.21
Average common shares outstanding
Basic		35,523			34,618			35,488			34,111
Diluted		35,523			34,618			42,114			42,720

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PART I - FINANCIAL INFORMATION - (Continued)

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

        
OVERVIEW AND OTHER INFORMATION (Continued)    

Comparison of second quarter 2007 and second quarter 2006 results - The Company’s net loss available to common shareholders was $3.0 million (or $0.08 per share) for the three months ended June 30, 2007, compared to $3.5 million (or $0.10 per share) for the three months ended June 30, 2006. The primary factors contributing to the lower net loss for the second quarter of 2007 compared to the second quarter of 2006 were an increase in gas distribution margin, an increase in non-operating income and a decrease in financing-related costs, offset partially by costs incurred in connection with the pending Share Exchange, an increase in operations and maintenance expense at the Gas Distribution Business and an increase in depreciation expense and property tax expense. The increase in gas distribution margin, which decreased the net loss for the second quarter of 2007 by approximately $1.3 million when compared to the second quarter of 2006, was primarily due to a rate increase in Michigan and higher consumption per customer.  The increase in non-operating income decreased the net loss by approximately $0.3 million, and was due primarily to interest income earned on higher levels of invested cash during the second quarter of 2007 when compared to the second quarter of 2006.  Financing-related costs, which consist of interest expense on debt and dividends on Preferred Stock, decreased primarily as a result of lower levels of outstanding debt and Preferred Stock.  The decrease in financing-related costs decreased the net loss by approximately $0.3 million, when comparing the second quarter of 2007 to the second quarter of 2006. Costs incurred during the second quarter of 2007 in connection with the pending Share Exchange increased the Company’s net loss by approximately $0.4 million.  The increase in operations and maintenance expense at the Gas Distribution Business, which increased the net loss for the second quarter of 2007 by approximately $0.7 million when compared to the second quarter of 2006, was primarily due to increases in uncollectible customer accounts and various other operating expenses, including employee compensation. The increase in depreciation expense and property tax expense, which increased the quarterly net loss by approximately $0.5 million, was due primarily to additional property and equipment placed in service.

Comparison of six months ended June 30, 2007, and six months ended June 30, 2006, results – The Company’s net income available to common shareholders was $12.1 million (or $0.32 per share) for the six months ended June 30, 2007, compared to $7.7 million (or $0.21 per share) for the six months ended June 30, 2006. The primary factors contributing to the increase in net income available to common shareholders when comparing the results for the six months ended June 30, 2007, to the results for the six months ended June 30, 2006, included an increase in gas distribution margin, an increase in non-operating income, profits earned by one of the Company’s non-regulated businesses from the sale of natural gas and a decrease in financing-related costs, offset partially by costs incurred in connection with the pending Share Exchange, an increase in operations and maintenance expense at the Gas Distribution Business and an increase in depreciation expense and property tax expense. The increase in gas distribution margin, which increased net income for the first six months of 2007 by approximately $6.5 million when compared to the first six months of 2006, was primarily due to a rate increase in Michigan and higher consumption per customer.  The increase in non-operating income increased net income by approximately $0.4 million, and was due primarily to interest earned on higher levels of invested cash during the first six months of 2007 when compared to the first six months of 2006. The profits earned by one of the Company’s non-regulated businesses on the sale of natural gas inventory increased net income for the first six months of 2007 by approximately $0.4 million when compared to the first six months of 2006. Financing-related costs decreased primarily as a result of lower levels of outstanding debt and Preferred Stock. The decrease in financing-related costs increased net income by approximately $0.9 million, when comparing the first six months of 2007 to the first six months of 2006. Costs incurred during the first six months of 2007 in connection with the pending Share Exchange decreased the Company’s net income by approximately $2.2 million.  The increase in operations and maintenance

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PART I - FINANCIAL INFORMATION - (Continued)

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

        
OVERVIEW AND OTHER INFORMATION (Continued)    

expense at the Gas Distribution Business, which decreased net income for the six months ended June 30, 2007, by approximately $1.1 million when compared to the six months ended June 30, 2006, was primarily due to increases in insurance and claims costs, uncollectible customer accounts, and various other operating expenses, including employee compensation, partially offset by a charge incurred in connection with a sublease during the first quarter of 2006 that did not recur in 2007.  The increase in depreciation expense and property tax expense, which decreased net income by approximately $0.9 million, was due primarily to additional property and equipment placed in service.

Pending Sale of the Company – For information regarding the pending Share Exchange, refer to Note 9 of the Condensed Notes to the Unaudited Consolidated Financial Statements in Part 1, Item 1 of this Quarterly Report on Form 10-Q.

The Impact of Higher Natural Gas Prices – The market price of natural gas has increased substantially during the past 5 years.  The following table shows the Company’s average cost of gas sold by the Company in Michigan and Alaska over the past several years and the year-to-date periods ended June 30, 2007, and June 30, 2006:

	Average cost of gas sold per Mcf
Period	Michigan		Alaska
Year-to-date June 30, 2007	$	8.37	$	7.03
Year-to-date June 30, 2006		9.42		5.00
Year 2006		8.94		5.00
Year 2005		8.47		3.93
Year 2004		6.39		3.11
Year 2003		5.60		2.56
Year 2002		3.86		2.51
Year 2001		3.24		2.36
Year 2000		3.15		1.63

 In Michigan, the Company purchases natural gas throughout the year, in order to (i) meet current customer needs, (ii) inject gas into storage for use by customers during the winter heating season, and (iii) have sufficient supplies under contract for the winter heating season. A decline in natural gas prices since mid-December 2005 has reduced the average price the Company has paid (through June 30, 2007) to purchase gas sold to customers during the 2006-2007 winter heating season, when compared to the 2005-2006 winter heating season. Despite this decline, prices are still higher on average than they were earlier this decade. The Company believes that higher natural gas prices will persist and that gas prices will remain volatile and could increase in the future 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.

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PART I - FINANCIAL INFORMATION - (Continued)

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

        
OVERVIEW AND OTHER INFORMATION (Continued)    

In Alaska, the Company’s facilities are located near natural gas supplies, and the Company has RCA-approved gas purchase contracts with various Cook Inlet area producers. The price of gas purchased under these contracts is adjusted annually in January. A portion of the natural gas purchased by the Company for its Alaska customers is priced on a 36-month trailing average price for natural gas, so price increases that occurred in the natural gas market during 2005 and early-2006 were not yet fully reflected in the price the Company paid for gas sold to customers in its Alaska service area through the end of 2006. However, the price the Company pays for gas under these contracts has increased over the past few years and, on January 1, 2007, the price increased to approximately $7.00 per one thousand standard cubic feet (“Mcf”) (an increase of approximately $2.00 per Mcf) based on these trailing average prices and oil-based indexes in the Company’s gas contracts.

In general, the cost of natural gas purchased for customers is recovered on a dollar-for-dollar basis (in the absence of disallowances), without a profit. The recovery of these gas costs is accomplished through the Company’s GCR pricing mechanisms, through which customer rates are periodically adjusted for increases and decreases in the cost of gas purchased by the Company for sale to customers. For additional information on the GCR pricing mechanisms, 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 Part II, Item 8 of the Company’s 2006 Annual Report on Form 10-K.

When gas prices are volatile and increase substantially, 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, such actions may decrease customer consumption, increase delinquent or uncollectible accounts, and increase the value of lost and unaccounted for (“LAUF”) natural gas volumes. These and other factors could result in an increase in working capital requirements and the need for the Company to borrow additional amounts under its Bank Credit Agreement or one or more Lines of Credit, if available.

The Company has been addressing, and continues to address, the impact of higher and more volatile natural gas prices by (i) seeking timely GCR rate increases in Michigan when gas prices increase, (ii) monitoring working capital requirements, (iii) evaluating customer consumption, (iv) monitoring customer payment patterns, and (v) seeking changes in rate design (meaning the way in which the costs of providing service to customers are collected in rates) to help reduce the impact of higher and more volatile natural gas prices on the Company’s financial performance and align Company and customer interests with respect to conservation.

During certain periods of the past two years when natural gas prices increased significantly over a short period of time, the Company was successful in obtaining GCR rate increases in Michigan on a timely basis to recover the higher gas costs. Timely GCR rate changes have helped reduce the Company’s working capital requirements by eliminating the need to finance for an extended period any under-recovery of gas costs not recouped in current GCR rates. Higher gas costs have increased the Company’s need for additional working capital for other purposes, however, such as to finance gas purchases at higher market prices, finance storage inventory, and carry accounts receivable. The recent decline in natural gas prices for gas sold to customers in Michigan has reduced the Company’s working capital requirements, but this positive effect has been partially offset by additional working capital requirements at the Company’s Alaska operations as a result of the increase in the cost of gas there.  Overall working capital requirements would likely increase if natural gas prices increased again in the future.

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PART I - FINANCIAL INFORMATION - (Continued)

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

        
OVERVIEW AND OTHER INFORMATION (Continued)    

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. Customer rates in Alaska increased by approximately 30% on January 1, 2007, as a result of increases in prices under the Company’s RCA-approved long-term gas supply contracts, which are reflected in the GCR portion of customer rates. Based on this and other factors (including the possibility of future price increases in Michigan and Alaska), the Company is unable to estimate, with certainty, the amount of future conservation (if any) that is likely to occur. 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, 2007, and 2006.

Higher gas costs, to the extent they are reflected in GCR rates, may also affect the ability of some customers to pay their bills for gas service on time or in full. The Company is, and has been, monitoring customer payment patterns and encouraging customers to elect budget-type levelized payment plans in order to spread winter heating season bills over a 12-month period. In addition to disconnecting service to delinquent customers, as necessary and permitted, the Company refers customers to sources of charitable and public assistance. The Company also participates in efforts to secure charitable donations that will provide such assistance.  The Company’s expense for uncollectible gas sales customer accounts was $2.5 million and $2.0 million for the six months ended June 30, 2007, and the six months ended June 30, 2006, respectively. The Company cannot provide any assurance that its future expense for uncollectible accounts will be consistent with its prior experience, in view of the various factors affecting customer payment patterns, including the recent declines in gas prices in Michigan and increases in gas prices in Alaska.

Higher gas costs also increase the expense associated with LAUF gas in the Company’s Michigan service areas, assuming that LAUF volumes are consistent period to period. Annual LAUF volumes in Michigan have ranged from 0.5% to 1.4% of volumes sold and transported in the Company’s Michigan service area over the last 10 years. The Company’s Michigan gas distribution operation typically accounts for 46% to 57% of total volumes sold and transported by the Company. LAUF gas volumes in Michigan for the six months ended June 30, 2007, and 2006, were 325 million standard cubic feet (“MMcf”) and 231 MMcf, respectively, or 0.97% and 0.75%, respectively, of volumes sold and transported in Michigan. The expense associated with LAUF gas in Michigan was $2.7 million and $2.3 million for the six months ended June 30, 2007, and 2006, respectively. The expense for LAUF gas did not increase in proportion to the increase in LAUF gas volumes because of the decline in gas prices at the Company’s Michigan operations between quarters.

The Company proposed to change various aspects of its rate design in the rate case it filed with the MPSC in 2006. A settlement of this rate case was approved by the MPSC in January 2007. The approved rate design changes are described in Note 2 of the Notes to the Consolidated Financial Statements in Part II, Item 8 of the Company’s 2006 Annual Report on Form 10-K. Except for a residential billing determinant change and an increase in the residential customer charge, the rate design changes proposed by the Company were not part of the MPSC-approved settlement. The rate case order did address the continuing decline in residential customer consumption, however, by changing a key billing element included in residential base rates. In an MPSC order issued in the Company’s previous rate case proceeding in March 2005, residential base rates were set using annual customer usage of about 113 Mcf of natural gas. In the MPSC order issued in January 2007, residential base rates were set using annual customer usage of 96 Mcf of natural gas. This significant reduction in the residential billing determinant recognizes that residential customer consumption has been steadily declining and sets base rates using an annual volume of gas consumption per customer that may be reasonably expected to be sold in a year with normal weather under current consumption patterns.

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PART I - FINANCIAL INFORMATION - (Continued)

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

        
OVERVIEW AND OTHER INFORMATION (Continued)    

In connection with future rate cases and other proceedings in Michigan and Alaska, the Company will continue to assess the need for rate design changes and propose changes that take into consideration the changing business environment in which the Company operates, including trends such as higher and more volatile natural gas prices and declining per customer consumption.

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

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PART I - FINANCIAL INFORMATION - (Continued)

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

        
OVERVIEW AND OTHER INFORMATION (Continued)    

The following table provides temperature and customer consumption data for the six-month periods ended June 30, 2007, and June 30, 2006:

	Six Months Ended
	June 30,
	2007			2006
Michigan
Degree days (DD) (a)
Actual		3,977			3,692
Normal (b)		4,202			4,225
Actual DD as a percent of normal DD		94.6	%		87.4	%
Percent by which actual DD differ from:
Normal DD (c)		(5.4	)%		(12.6	)%
Prior year actual DD (d)		7.7	%		(13.0	)%
Average gas consumption per customer (Mcf)
Residential gas sales customers		61.7			53.9
Residential gas sales customers normalized (e)		65.2			61.7
Percent by which residential gas sales customers normalized differs from prior year residential gas sales customers normalized (f)		5.6	%		(4.3	)%
All gas sales customers		85.1			75.7
All gas sales customers normalized (e)		89.9			86.6
Percent by which all gas sales customers normalized differs from prior year all gas sales customers normalized (f)		3.8	%		(3.9	)%
Alaska
Degree days (DD) (a)
Actual		5,946			5,831
Normal (b)		5,307			5,500
Actual DD as a percent of normal DD		112.0	%		106.0	%
Percent by which actual DD differ from:
Normal DD (c)		12.0	%		6.0	%
Prior year actual DD (d)		2.0	%		12.9	%
Average gas consumption per customer (Mcf)
Residential gas sales customers		98.1			98.8
Residential gas sales customers normalized (e)		87.6			93.2
Percent by which residential gas sales customers normalized differs from prior year residential gas sales customers normalized (f)		(6.0	)%		(3.3	)%
All gas sales customers, excluding large general services (g)		110.7			111.4
All gas sales customers, excluding large general services, normalized (e)		98.8			105.1
Percent by which all gas sales customers normalized differs from prior year all gas sales customers normalized (f)		(6.0	)%		(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 15 years. For 2006, normal degree days for the Company’s Alaska operations was determined using a 10-year average of degree days and for 2007, normal degree days for the Company’s Alaska operations is determined using a 10-year seasonal regression (“winters”) model.
(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)	Normalized average annual 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.
(f)	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 most likely due to changes in energy conservation by customers.
(g)	As a result of a gas supplier no longer supplying natural gas to certain transportation (large general service) customers in Alaska, these transportation customers have switched from gas (large general) transportation service to gas (large general) sales service. As large general service customers are much less weather sensitive, the Company has removed this category of customers from this calculation for all years presented.

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PART I - FINANCIAL INFORMATION - (Continued)

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

        
OVERVIEW AND OTHER INFORMATION (Continued)    

The Company has estimated that, in its Michigan service area, temperatures were approximately 5.4% warmer than normal during the first six months of 2007 and approximately 12.6% warmer than normal during the first six months of 2006. In the Company’s Alaska service area, temperatures are estimated to have been approximately 12.0% colder than normal during the first six months of 2007 and approximately 6.0% colder than normal during the first six months of 2006.

The Company has estimated that, in its Michigan service area, normalized average gas consumption during the first six months of 2007 for all gas sales customers increased by approximately 3.8%, when compared to 2006. This increase in consumption comes after several years of declining consumption and is believed to be the result of lower gas prices during the first six months of 2007, when compared to prices during the first six months of 2006, and other factors influencing customer consumption.  Despite the increase in average gas consumption per customer in Michigan during 2007, the Company believes that the long-term trend of declining per customer gas consumption will continue in the future.

In the Company’s Alaska service area, normalized average gas consumption during the first six months of 2007 for all gas sales customers decreased by an estimated 6.0%, when compared to 2006.  This decrease in per customer consumption in Alaska is likely due in large part to customer conservation prompted by the 30% increase in customer rates as a result of increases in prices under the Company’s RCA-approved long-term gas supply contracts and other factors influencing customer consumption.

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 other 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 Quarterly Report on 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 Quarterly Report on Form 10-Q.

The Gas Distribution Business segment analysis and other discussions below provide additional information regarding variations in operating results when comparing the three- and six-month periods ended June 30, 2007, 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, or other non-operating income and expense items.  A review of the non-operating items follows the business segment discussion.

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 DISTRIBUTION BUSINESS SEGMENT

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, 2007, and 2006, are not necessarily indicative of results for a full year.

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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)           

Gas Sales Revenue– The Company’s gas sales revenue was $110.6 million and $407.3 million, respectively, for the three and six months ended June 30, 2007, compared to $87.1 million and $343.6 million, respectively, for the three and six months ended June 30, 2006.  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 Part II, Item 8 of the Company’s 2006 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.

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2007			2006			2007			2006
	(dollars in thousands)
Gas sales revenues	$	110,609		$	87,122		$	407,288		$	343,605
Cost of gas sold		83,890			63,515			326,218			276,119
Gas sales margin	$	26,719		$	23,607		$	81,070		$	67,486
Gas transportation revenue		4,720			6,153			12,418			15,545
Other operating revenue		2,831			2,389			5,141			5,278
	$	34,270		$	32,149		$	98,629		$	88,309
Operation and maintenance		19,779			18,655			38,607			36,809
Depreciation and amortization		7,179			6,888			14,332			13,704
Property and other taxes		2,586			2,058			5,769			4,924
Operating income	$	4,726		$	4,548		$	39,921		$	32,872
Volumes of gas sold (MMcf)		10,769			9,417			41,784			36,048
Volumes of gas transported (MMcf)		8,925			12,752			20,699			27,275
Number of customers at end of period		410,114			408,826			410,114			408,826
Degree Days
Alaska		1,583			1,712			5,946			5,831
Michigan		803			750			3,977			3,692
Percent colder (warmer) than normal
Alaska		5.3	%		6.5	%		12.0	%		6.0	%
Michigan		(13.9	)%		(19.5	)%		(5.4	)%		(12.6	)%
The amounts in the above table include intercompany transactions.

- 31 -

PART I - FINANCIAL INFORMATION - (Continued)

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

        
GAS DISTRIBUTION BUSINESS SEGMENT (Continued)           

Gas Sales Margin – The Company’s gas sales margin is derived primarily from customer service fees and consumption-based distribution charges.  The customer service fees 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 margins and, in the Company’s view, may impact future gas sales margins. These factors are changes in: (i) customer gas consumption; (ii) the number of gas sales customers; (iii) LAUF gas expense; and (iv) customer rates.

In addition to these recurring items, another factor impacted results for the three and six months ended June 30, 2007. During late-2006, approximately 700 gas transportation customers in Alaska switched from gas transportation service to gas sales service (large general service class). This service changeover occurred because a third-party gas supplier stopped supplying natural gas to these transportation customers in late-2006. The gas for these new sales customers in Alaska is being supplied under the Company’s existing gas supply agreements. The Company’s margins from these customers after the date of the changeover to sales service is reported in gas sales margin rather than gas transportation revenue. During the three-month and six-month periods ended June 30, 2007, gas sales margins from large general service customers in Alaska increased by approximately $0.7 million and $3.5 million, respectively, when compared to the same periods ended June 30, 2006, due in large part to this service changeover, including the impact of revisions to a special contract discussed below. For all but one of these customers, however, the Company does not expect that this change from gas transportation service to gas sales service will affect the Company’s operating income significantly, because the margins under either service are the same.

The Company negotiated a special contract with one of the affected transportation customers, a public utility, which resulted in gas sales margins that were higher than the margins the Company earned previously from this customer for providing transportation service. This special contract was put into effect on an interim basis in October 2006, subject to refund, pending final RCA approval of the contract. In an order dated May 31, 2007, the RCA approved the contract with revisions that decreased the margins the Company could earn under the contract. The decrease in margins earned during the interim period from this customer (which amounted to $0.4 million) was recorded in the Company’s results of operations upon receiving the RCA order.  Despite the revisions to the special contract, the Company still expects annual gas sales margins earned from this customer under the special contract to be approximately $0.3 million higher than the annual margins earned previously from this customer for providing transportation services.

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. An increase in customer gas consumption during the three and six months ended June 30, 2007, increased gas sales margin by approximately $0.7 million and $3.3 million, respectively, when compared to the same periods ended June 30, 2006.  Temperatures in Michigan during the first six months of 2007 were approximately 7.7% colder than during the first six months of 2006 and temperatures in Alaska during the first six months of 2007 were approximately 2.0% colder than during the first six months of 2006.  Normalized gas consumption, which is a measure the Company uses to estimate customer conservation from one period to another, increased in Michigan during the first six months of 2007, when compared to the first six months of 2006, but was partially offset by the impact of a decrease in normalized gas consumption in Alaska, when comparing the same periods.  Normalized consumption per gas sales customer increased by an estimated 3.8% in Michigan and decreased by an

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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)           

estimated 6.0% in Alaska, when comparing the first six months of 2007 to the first six months of 2006.  The Company believes the decrease in normalized gas consumption per gas sales customer in Alaska was likely due to conservation prompted by the 30% increase in customer rates caused by increases in prices under the Company’s RCA-approved long-term gas supply contracts. The increase in normalized gas consumption in Michigan comes after several years of declining consumption and is believed to be the result of lower gas prices in Michigan during the first six months of 2007, when compared to prices during the first six months of 2006.  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 1.1% and 3.3%, respectively, during the past three years. For the six-month period ended June 30, 2007, the average number of gas distribution customers in Michigan increased by less than 0.1% and in Alaska increased by approximately 1.9%, when compared to the six-month period ended June 30, 2006. The additional customers increased gas sales margins for the six months ended June 30, 2007, by approximately $0.3 million, when compared to the same period ended June 30, 2006.

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 the three and six months ended June 30, 2007, by approximately $0.3 million and $0.4 million, respectively, when compared to the same periods ended June 30, 2006.  The cost of LAUF gas is affected by the underlying commodity cost and rate mechanisms employed to price LAUF gas volumes and recover this cost from customers.

The remainder of the change in gas sales margins was due primarily to changes in rates, as well as other miscellaneous factors. During the three and six months ended June 30, 2007, these factors increased gas sales margins by approximately $2.0 million and $6.9 million, respectively, when compared to the same periods ended June 30, 2006. There was an increase in rates effective on January 10, 2007, for MPSC-regulated customers. The rate increase for MPSC-regulated customers was the result of a rate case settlement approved by the MPSC. 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 Part II, Item 8 of the Company’s 2006 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, 2007, gas transportation revenue decreased by $1.4 million and $3.1 million, respectively, when compared to the same periods ended June 30, 2006.  The decreases were primarily due to approximately 700 gas transportation customers in Alaska switching to gas sales service in the fourth quarter of 2006, as discussed under the caption “Gas Sales Margin” above, and a decrease in transportation volumes from a fertilizer manufacturing customer discussed below, partially offset by increases in usage by the Company’s other remaining transportation customers, due primarily to colder temperatures and other factors.

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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)           

One of the Company’s Alaska service area industrial transportation customers, a fertilizer manufacturer, has publicly announced that it has experienced difficulty in securing sufficient natural gas supplies at an appropriate price to continue operating in the future. The customer has indicated that it has secured sufficient natural gas supplies to operate at a reduced rate through October 2007, but currently does not have sufficient natural gas under contract at an appropriate price to operate after that date. During the winter period from October 2006 through April 2007, this facility was shut down due to the lack of seasonal gas supply. Transportation revenues from this customer totaled $1.2 million in 2006. Based upon volumes transported during the first six months of 2007 and estimates provided by the customer, transportation revenues from this customer are expected to total $0.6 million in 2007. The Company cannot predict the likely pattern of future operations at this plant, including whether the plant will ultimately close.

Other Operating Revenue - For the three months ended June 30, 2007, other operating revenue increased by $0.4 million when compared to the three months ended June 30, 2006.  This increase was primarily due to increases in miscellaneous customer revenues, which include amounts from various service fees and late payment fees charged to customers.  For the six months ended June 30, 2007, other operating revenue decreased by approximately $0.1 million when compared to the same period ended June 30, 2006. The decrease was due primarily to a decrease in miscellaneous customer revenues.

Operations and Maintenance Expenses - For the three and six months ended June 30, 2007, operations and maintenance (“O&M”) expenses increased by $1.1 million and $1.8 million, respectively, when compared to the same periods ended June 30, 2006.  The increase in O&M expenses between quarters was primarily due to an increase in uncollectible customer accounts expense of approximately $0.5 million and increases in various other operating expenses, including employee compensation, which approximated $0.6 million.  The increase in O&M expenses when comparing the first six months of 2007 to the first six months of 2006 was due in part to a $0.5 million increase in insurance and claims expense and a $0.5 million increase in uncollectible customer accounts expense.  The remainder of the increase ($0.8 million) when comparing the six-month periods ended June 30, 2007, and 2006, was due to increases in various other operating expenses, including employee compensation, partially offset by a $1.2 million charge reflected in O&M expenses for the first six months of 2006, related to the sublease of the Company’s former headquarters, that did not recur in 2007.

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 increased for the three and six months ended June 30, 2007, when compared to the same periods ended June 30, 2006. The increase is primarily attributed to property taxes on net additional property, plant and equipment placed in service as part of expanding and upgrading the Company’s gas distribution system.

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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)           

Regulatory and Other Matters – Refer to Notes 9 and 10 of the Condensed Notes to the Unaudited Consolidated Financial Statements in Part 1, Item 1 of this Quarterly Report on Form 10-Q for information about current regulatory matters.

The Company continues to evaluate how to meet the long-term natural gas supply needs of its customers in Alaska.  These evaluations include new gas supply contracts and possible additional gas storage facilities and new gas transmission lines, including various combinations of these alternatives.  The Company’s evaluations and activities related to these matters are ongoing.

CORPORATE AND OTHER

	Three Months Ended					Six Months Ended
	June 30,					June 30,
	2007			2006		2007			2006
	(in thousands)
Operating revenues	$	3,265		$	3,372	$	10,762		$	8,015
Other operating expenses		3,468			3,357		12,701			7,290
Operating income (loss)	$	(203	)	$	15	$	(1,939	)	$	725
The amounts in the above table include intercompany transactions.

Operating Revenues – Corporate and Other reported operating revenue of $3.3 million and $10.8 million, respectively, for the three and six months ended June 30, 2007, compared to operating revenue of $3.4 million and $8.0 million, respectively, for the same periods ended June 30, 2006.  The $2.8 million increase in operating revenues when comparing the first six months of 2007 to the first six months of 2006 was due primarily to the sale of natural gas inventory during the first quarter of 2007, which amounted to approximately $2.3 million (there were no comparable sales of natural gas inventory during the first six months of 2006), and an increase in propane revenues, which amounted to approximately $0.6 million. The increase in propane revenues was due primarily to colder weather during the first six months of 2007, when compared to the first six months of 2006.

Operating Income – Corporate and Other reported operating losses of $0.2 million and $1.9 million, respectively, for the three and six months ended June 30, 2007, compared to operating income of approximately break even and $0.7 million, respectively, for the same periods ended June 30, 2006. The $0.2 million decrease in operating income for the three-month period ended June 30, 2007, was due primarily to $0.6 million of costs incurred in connection with the pending Share Exchange, partially offset by a write-down of natural gas inventory during the second quarter of 2006, which did not recur in 2007. The $2.7 million decrease in operating income for the six-month period ended June 30, 2007, was due primarily to $3.5 million of costs incurred in connection with the pending Share Exchange, partially offset by margins earned on the sale of natural gas inventory during the first quarter of 2007 and the 2006 write-down of natural gas inventory discussed above.

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PART I - FINANCIAL INFORMATION - (Continued)

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

OTHER INCOME AND DEDUCTIONS

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2007			2006			2007			2006
	(in thousands)
Interest expense	$	(9,496	)	$	(10,181	)	$	(19,524	)	$	(20,730	)
Other income		1,165			807			2,075			1,363
Total other income (deductions)	$	(8,331	)	$	(9,374	)	$	(17,449	)	$	(19,367	)

Interest Expense - Interest expense for the three and six months ended June 30, 2007, decreased by $0.7 million and $1.2 million, respectively, when compared to the same periods ended June 30, 2006. Approximately $0.3 million and $0.7 million of the decreases for the three and six months ended June 30, 2007, were primarily due to lower levels of short-term bank borrowings under the Company’s Bank Credit Agreement and Lines of Credit. The lower levels of short-term bank borrowings were due primarily to the availability of increased cash flows as a result of a rate increase in Michigan and colder temperatures during 2007, when compared to 2006.  Also contributing to the decrease in interest expense was the redemption of $59.5 million of the Company’s 8% Senior Notes due 2016 in November 2006 and their replacement with the Bank Term Loan with a lower variable rate of interest.  In addition, the Company reduced interest expense by repaying $15 million of the Bank Term Loan in the second quarter of 2007. For additional information on the Bank Term Loan repayment, refer to Note 2 of the Condensed Notes to the Unaudited Consolidated Financial Statements in Part 1, Item 1 of this Quarterly Report on Form 10-Q.

Other Income – Other income for the three and six months ended June 30, 2007, increased by $0.4 million and $0.7 million, respectively, when compared to the same periods ended June 30, 2006. These increases were primarily due to additional interest income earned on higher levels of invested cash during the first six months of 2007, when compared to the first six months of 2006.

INCOME TAXES

Income tax expense (benefit) was $(1.5) million and $7.1 million, respectively, for the three and six months ended June 30, 2007, and $(1.8) million and $5.1 million, respectively, for the same periods ended June 30, 2006.  The change in income taxes, when comparing one period to another, is due primarily to changes in earnings before income taxes.

DIVIDENDS ON CONVERTIBLE CUMULATIVE PREFERRED STOCK

Dividend expense for the Preferred Stock amounted to $0.7 million and $1.3 million, respectively, for the three- and six-month periods ended June 30, 2007, and $0.5 million and $1.5 million, respectively, for the three- and six-month periods ended June 30, 2006. The decrease in the dividends when comparing these periods is due to the impact of the Company’s repurchase and subsequent retirement of a portion of the Preferred Stock in the second quarter of 2006. For further information on Preferred Stock, the cash dividends on Preferred Stock and the repurchase and retirement of Preferred Stock, refer to Note 4 of the Notes to the Consolidated Financial Statements in Part II, Item 8 of the Company’s 2006 Annual Report on Form 10-K, and Note 2 of the Condensed Notes to the Unaudited Consolidated Financial Statements in Part 1, Item 1 of this Quarterly Report on Form 10-Q.

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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

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, 2007, and 2006:

	Six Months Ended
	June 30,
	2007		2006
	(in thousands)
Capital investments:
Property additions - gas distribution	$	13,364	$	21,280
Property additions - corporate and other		298		120
	$	13,662	$	21,400

The Company’s expenditures for property additions were approximately $13.7 million for the first six months of 2007.  Expenditures for property additions during the remainder of 2007 are anticipated to be approximately $26.0 million.

Cash Flows Provided By Operations– The Company’s net cash provided by operating activities totaled $110.4 million for the six-month period ended June 30, 2007, compared to $84.7 million for the same period ended June 30, 2006. 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 sale to 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 $81.0 million for the six-month period ended June 30, 2007, compared to $61.6 million for the same period ended June 30, 2006.

	Six Months Ended
	June 30,
	2007			2006
	(in thousands)
Cash provided by (used for) financing activities:
Issuance of common stock, net of expenses	$	951		$	43
Repurchase of convertible cumulative preferred stock, net of expenses		-			(12,587	)
Repayment of notes payable and payment of related expenses		(65,700	)		(47,700	)
Repayment of long-term debt		(15,000	)		(92	)
Payment of dividends on convertible cumulative preferred stock		(1,196	)		(1,623	)
Change in book overdrafts included in current liabilities		(98	)		359
	$	(81,043	)	$	(61,600	)

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PART I - FINANCIAL INFORMATION - (Continued)

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

LIQUIDITY AND CAPITAL RESOURCES (Continued)                    

Future Financing Plans – The Company’s capital structure at June 30, 2007, consisted of approximately 60.1% total debt (including current maturities and notes payable), 6.5% preferred stock and 33.4% 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. On April 5, 2007, and May 29, 2007, the Company repaid $10 million and $5 million, respectively, of its Bank Term Loan, which matures on June 30, 2016, leaving $40 million outstanding. Given the Company’s improved year-to-date cash flow and strengthened liquidity position, the Company is evaluating the potential for repaying an additional $10 million to $20 million of long-term debt during the third quarter of 2007. Although there are no other specific plans to issue equity or further reduce long-term debt during the remainder of 2007 (notwithstanding the potential retirement of debt if the Share Exchange is completed as discussed below), the Company will continue to identify and, as appropriate, take advantage of market opportunities to do so as they arise.

In general, the Company funds its capital expenditures with operating cash flows and borrowings under its Bank Credit Agreement and Lines of Credit, if available. When appropriate, the Company will refinance its short-term debt with long-term debt, Common Stock issuances or other long-term financing instruments. Refer to Note 2 of the Condensed Notes to the Unaudited Consolidated Financial Statements in Part 1, Item 1 of this Quarterly Report on Form 10-Q for information regarding the Bank Credit Agreement, including a description of the covenants contained in the Bank Credit Agreement. As of June 30, 2007, 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 and Lines of Credit typically also will follow a seasonal pattern. The Company expects to use funds available under the Bank Credit Agreement and Lines of Credit, if available, to finance, on a short-term basis, the variability and seasonality of its operating cash flow and working capital requirements. Typically, as the Company collects cash from winter heating sales in the latter part of the first quarter and the second quarter, it will pay down the borrowings under the Bank Credit Agreement and Lines of Credit. During the summer months, it will reduce its short-term borrowings under the Bank Credit Agreement and Lines of Credit, and may build up sufficient cash to enable it to enter into short-term investments. As gas is purchased throughout the summer and injected into storage in preparation for the winter heating season and the Company completes its annual construction program, the Company expects to incur borrowings under the Bank Credit Agreement and Lines of Credit, if available. 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 can also be affected by numerous factors, including the credit terms under which the Company purchases natural gas for sale to customers, its GCR rates in various jurisdictions and its relative levels of gas storage inventory.

In the event that the Share Exchange is consummated, the indentures under which long-term debt of $150 million due 2008 and $200 million due 2013 was issued provide that, upon the occurrence of a change of control of the Company, the Company shall make an offer to repurchase all or any part of the notes at a purchase price equal to 101% of the aggregate principal amount of the indebtedness. In addition, under the terms of the agreements which govern the Bank Term Loan, Bank Credit Agreement and Lines of Credit, an event of default would occur upon a change of control of the Company. In such an event, the lenders may declare any outstanding amounts immediately due and payable. The Share Exchange would be considered a change of control under these agreements. The financing commitment provided in connection with the Share Exchange covers amounts that may be payable under these indentures and agreements.

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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 - In the event that the Share Exchange is not consummated, the Company would likely consider, 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

In June 2006, the FASB issued Financial Interpretation Number (‘‘FIN’’) 48, ‘‘Accounting for Uncertainty in Income Taxes – an interpretation of SFAS No. 109.” In September 2006, the FASB issued SFAS 157, “Fair Value measurements.” In February 2007, the FASB issued SFAS 159, “The Fair Value Option for Financial Assets and Financial Liabilities – Including an amendment of FASB Statement No. 115.” Refer to the “New Accounting Standards” section of Note 1 of the Condensed Notes to the Unaudited Consolidated Financial Statements in Part 1, Item 1 of this Quarterly Report on 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 the section titled “Market Risk Information” in Part I, Item 7 in the Company’s 2006 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 Quarterly Report on 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, 2007, to insure that information related to the Company required to be disclosed in reports the Company files or submits under the Exchange Act is (i) recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and (ii) accumulated and communicated to the Company’s management, including the CEO and CFO, to allow timely decisions regarding required disclosure. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that the Company’s disclosure controls and procedures will detect or uncover every situation involving the failure of persons within the Company to disclose material information otherwise required to be set forth in the Company’s periodic reports; however, the Company’s disclosure controls are designed to provide reasonable assurance that they will achieve their objective of timely alerting the CEO and CFO to the information relating to the Company required to be disclosed in the Company’s periodic reports required to be filed with the SEC.

Changes in Internal Control Over Financial Reporting– During the quarter ended June 30, 2007, 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 Notes 8 and 10 of the Condensed Notes to the Unaudited Consolidated Financial Statements in Part I, Item 1 of this Quarterly Report on Form 10-Q.

Item 1A. Risk Factors.

None.

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

None.

Item 3.  Defaults upon Senior Securities.

Not applicable.

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

A special meeting of the Company’s shareholders was held on June 7, 2007, to approve the proposed Share Exchange. There were present at the meeting, either in person or by valid proxy, the holders of 24,732,194 shares of the Company, constituting a quorum. The results of the ballots cast by the holders of shares were as follows:

For	Against	Abstain	Broker Non-Votes
23,869,589	796,379	66,226	-

For additional information on the Exchange Agreement, refer to Note 9 of the Condensed Notes to the Unaudited Consolidated Financial Statements in Part I, Item 1 of this Quarterly Report on Form 10-Q.

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 44 for the Exhibit Index.)

Exhibits	Description
3.1	Articles of Incorporation of SEMCO Energy, Inc., as restated August 30, 2006 (incorporated herein by reference to Exhibit 3.1 to the Company’s Form 10-Q for the quarter ended September 30, 2006, filed November 6, 2006).
3.2	Amended and Restated Bylaws of SEMCO Energy, Inc., as amended through August 16, 2006 (incorporated herein by reference to Exhibit 3.2 to the Company’s Form 10-Q for the quarter ended September 30, 2006, filed November 6, 2006).
10.9.10*	Form of Restricted Stock Grant Agreement for Certain Directors.
31.1	CEO Certification, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2	CFO Certification, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1	CEO and CFO Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

___________________

* Indicates management contract or compensatory plan or arrangement.

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SIGNATURES

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

	SEMCO ENERGY, INC. (Registrant)
Date:  August 8, 2007	By:	/s/ Michael V. Palmeri
		Senior Vice President and Chief Financial Officer and Treasurer (Duly authorized officer, principal financial officer, and chief accounting officer)

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EXHIBIT INDEX

Form 10-Q

Second Quarter 2007

Exhibits	Description
3.1	Articles of Incorporation of SEMCO Energy, Inc., as restated August 30, 2006 (incorporated herein by reference to Exhibit 3.1 to the Company’s Form 10-Q for the quarter ended September 30, 2006, filed November 6, 2006).
3.2	Amended and Restated Bylaws of SEMCO Energy, Inc., as amended through August 16, 2006 (incorporated herein by reference to Exhibit 3.2 to the Company’s Form 10-Q for the quarter ended September 30, 2006, filed November 6, 2006
10.9.10*	Form of Restricted Stock Grant Agreement for Certain Directors.
31.1	CEO Certification, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2	CFO Certification, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1	CEO and CFO Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

___________________

* Indicates management contract or compensatory plan or arrangement.

- 44 -