Gas Natural 10-Q 2009 Q2 Quarterly report

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended June 30, 2009

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 0-14183

ENERGY, INC.

(Exact name of registrant as specified in its charter)

Montana (State or other jurisdiction of incorporation or organization)	81-0141785 (I.R.S. Employer Identification No.)
1 First Avenue South, Great Falls, Montana (Address of principal executive offices)	59401 (Zip Code)

Registrant’s telephone number, including area code:(406) 791-7500

ENERGY WEST, INCORPORATED
(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 filing requirements for the past 90 days. þ Yeso No

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). o Yeso No

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

Large accelerated filero Accelerated filero Non-accelerated filero Smaller reporting companyþ

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

The number of shares outstanding of the registrant’s common stock as of August 7, 2009 was 4,301,988 shares.

As used in this Form 10-Q, the terms “company”, “Energy, Inc.”, “Registrant”, “we”, “us”, and “our” mean Energy, Inc. and its consolidated subsidiaries as a whole, unless the context indicates otherwise. Except as otherwise stated, the information in this Form 10-Q is as of June 30, 2009.

ENERGY, INC.
INDEX TO FORM 10-Q

	Page No.
Part I — Financial Information
Item 1 — Financial Statements
Condensed Consolidated Balance Sheets (unaudited)  as of June 30, 2009, June 30, 2008 and December 31, 2008		3
Condensed Consolidated Statements of Income (unaudited) — three months ended June 30, 2009 and 2008, and six months ended June 30, 2009 and 2008		4
Condensed Consolidated Statements of Cash Flows — six months ended June 30, 2009 and 2008		5
Notes to Condensed Consolidated Financial Statements		6
Item 2 — Management’s Discussion and Analysis of Financial Condition and Results of Operations		15
Item 3 — Quantitative and Qualitative Disclosures about Market Risk		25
Item 4T — Controls and Procedures		26
Part II — Other Information
Item 6 — Exhibits		27
Signatures		28
Exhibit 31.1
Exhibit 31.2
Exhibit 32.1
Exhibit 32.2

2

PART I — FINANCIAL INFORMATION

ITEM 1 — FINANCIAL STATEMENTS.

ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

	June 30,					December 31,
	(unaudited)			(audited)		(audited)
	2009			2008		2008
ASSETS
Current Assets:
Cash	$	698,509		$	796,302	$	1,065,529
Marketable securities		5,702,732			910,778		3,376,875
Accounts and notes receivable less $191,990, $136,399, and $207,942, respectively, allowance for bad debt		3,031,605			5,108,796		7,430,694
Unbilled gas		825,951			1,252,638		4,839,138
Derivative assets		—			145,428		—
Natural gas and propane inventories		2,551,005			5,505,337		9,891,802
Materials and supplies		1,111,688			955,467		1,175,596
Prepayments and other		147,288			193,581		422,514
Income tax receivable		—			417,164		1,014,806
Recoverable cost of gas purchases		467,866			1,054,875		2,041,280
Deferred tax asset		971,850			—		225,953
Total current assets		15,508,494			16,340,366		31,484,187
Property, Plant and Equipment, Net		37,761,796			31,051,419		34,904,442
Deferred Tax Assets — Long-Term		5,272,114			6,825,575		5,693,310
Deferred Charges		2,312,255			2,761,656		2,558,156
Other Investments		1,311,208			1,118,264		1,081,423
Other Assets		83,123			279,810		97,447
TOTAL ASSETS	$	62,248,990		$	58,377,090	$	75,818,965
LIABILITIES AND CAPITALIZATION
Current Liabilities:
Bank overdraft	$	421,934		$	532,901	$	773,199
Accounts payable		3,749,995			7,439,748		5,783,927
Line of credit		3,600,000			—		17,551,276
Derivative liabilities		—			146,206		—
Accrued taxes		300,408			—		—
Deferred income taxes		—			18,039		—
Accrued and other current liabilities		3,939,497			3,302,712		4,982,684
Overrecovered gas purchases		2,205,472			522,347		1,022,853
Total current liabilities		14,217,306			11,961,953		30,113,939
Other Obligations:
Deferred investment tax credits		229,034			250,096		239,565
Other long-term liabilities		2,379,342			2,516,262		2,383,323
Total other obligations		2,608,376			2,766,358		2,622,888
Long-Term Debt		13,000,000			13,000,000		13,000,000
Commitments and Contingencies (see note 11)
Stockholders’ Equity:
Preferred stock; $.15 par value, 1,500,000 shares authorized, no shares outstanding		—			—		—
Common stock; $.15 par value, 15,000,000 shares authorized, 4,301,369, 4,347,394 and 4,296,603 shares outstanding at June 30, 2009 and 2008, and December 31, 2008, respectively		653,218			652,165		652,503
Treasury stock		(8,012	)		—		(8,012	)
Capital in excess of par value		5,975,868			6,280,649		5,926,028
Accumulated other comprehensive income		454,491			—		(319,147	)
Retained earnings		25,347,743			23,715,965		23,830,766
Total stockholders’ equity		32,423,308			30,648,779		30,082,138
TOTAL CAPITALIZATION		45,423,308			43,648,779		43,082,138
TOTAL LIABILITIES AND CAPITALIZATION	$	62,248,990		$	58,377,090	$	75,818,965

The accompanying notes are an integral part of these condensed financial statements.

3

ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	(unaudited)						(unaudited)
	2009			2008			2009			2008
REVENUES:
Natural gas operations	$	9,544,306		$	14,053,222		$	35,685,876		$	38,220,701
Gas and electric—wholesale		2,582,758			3,494,963			7,662,345			10,115,959
Pipeline operations		111,401			93,519			224,067			183,316
Total revenues		12,238,465			17,641,704			43,572,288			48,519,976
EXPENSES:
Gas purchased		5,029,479			9,655,513			24,464,331			27,364,970
Gas and electric—wholesale		1,960,833			3,381,082			6,085,727			8,910,737
Total cost of sales		6,990,312			13,036,595			30,550,058			36,275,707
GROSS MARGIN		5,248,153			4,605,109			13,022,230			12,244,269
Distribution, general, and administrative		2,525,331			3,309,542			5,420,885			6,059,970
Maintenance		185,183			121,448			356,590			324,638
Depreciation and amortization		531,471			488,675			1,045,145			975,923
Taxes other than income		482,686			571,687			1,112,266			1,216,531
Total expenses		3,724,671			4,491,352			7,934,886			8,577,062
OPERATING INCOME		1,523,482			113,757			5,087,344			3,667,207
OTHER INCOME (EXPENSE)		(84,939	)		77,529			(109,918	)		125,686
INTEREST EXPENSE		(252,399	)		(258,886	)		(598,351	)		(546,634	)
INCOME (LOSS) FROM OPERATIONS BEFORE INCOME TAX EXPENSE		1,186,144			(67,600	)		4,379,075			3,246,259
INCOME TAX EXPENSE		(500,059	)		(52,299	)		(1,730,267	)		(1,058,860	)
NET INCOME (LOSS)	$	686,085		$	(119,899	)	$	2,648,808		$	2,187,399
BASIC INCOME PER COMMON SHARE:
Income (loss) from continuing operations	$	0.16		$	(0.03	)	$	0.62		$	0.50
DILUTED INCOME PER COMMON SHARE:
Income (loss) from continuing operations	$	0.16		$	(0.03	)	$	0.62		$	0.50
DIVIDENDS DECLARED PER COMMON SHARE:	$	0.14		$	0.12		$	0.26		$	0.22
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING:
Basic		4,300,239			4,347,061			4,299,174			4,342,372
Diluted		4,303,121			4,348,961			4,302,036			4,343,914

The accompanying notes are an integral part of these condensed financial statements.

4

ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

	Six Months Ended
	June 30,
	(unaudited)
	2009			2008
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	2,648,808		$	2,187,399
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization, including deferred charges and financing costs		1,231,030			1,102,503
Stock-based compensation		50,555			249,090
Derivative assets		—			(81,242	)
Derivative liabilities		—			81,849
Deferred gain		—			(120,758	)
Investment tax credit		(10,531	)		(10,531	)
Deferred income taxes		195,822			(294,210	)
Changes in assets and liabilities:
Accounts and notes receivable		8,412,275			4,516,982
Natural gas and propane inventories		7,340,796			2,565,269
Accounts payable		(2,431,551	)		1,288,294
Recoverable/overrecovered cost of gas purchases		2,756,033			(148,542	)
Prepayments and other		275,226			444,275
Other assets & liabilities		(618,731	)		(2,232,558	)
Net cash provided by operating activities		19,849,732			9,547,820
CASH FLOWS FROM INVESTING ACTIVITIES:
Construction expenditures		(3,923,127	)		(2,485,292	)
Purchase of marketable securities		(1,068,727	)		(1,233,033	)
Sale of mareketable securities		—			390,746
Other investments		(229,785	)		(100,867	)
Customer advances received for construction		(55,359	)		63,669
Increase from contributions in aid of construction		65,139			86,804
Net cash used in investing activities		(5,211,859	)		(3,277,973	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from line of credit		7,300,000			5,600,000
Repayment of notes payable		(21,195,000	)		(12,125,495	)
Repurchase of common stock		—			(10,740	)
Sale of common stock		—			112,460
Dividends paid		(1,109,893	)		(955,031	)
Net cash used in financing activities		(15,004,893	)		(7,378,806	)
NET DECREASE IN CASH AND CASH EQUIVALENTS		(367,020	)		(1,108,959	)
CASH AND CASH EQUIVALENTS:
Beginning of period		1,065,529			1,905,261
End of period	$	698,509		$	796,302

The accompanying notes are an integral part of these condensed financial statements.

5

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

Basis of Presentation

Effective December 31, 2008, the Company changed its fiscal year end from June 30 to December 31. This change was made to align the Company’s fiscal year end with other companies within the industry. The resulting six-month period ended December 31, 2008 may be referred to herein as the “Transition Period.”

Effective on August 3, 2009, Energy West, Incorporated reorganized into a holding company organizational structure pursuant to an Agreement and Plan of Merger with, among others, Energy, Inc. The primary purpose of the reorganization is to provide flexibility to make future acquisitions through subsidiaries of the new holding company rather than Energy West or its subsidiaries. The business operations of the Company will not change as a result of the reorganization.

The accompanying unaudited condensed consolidated financial statements of Energy, Inc. and its subsidiaries (collectively, the “Company”) have been prepared in accordance with accounting principles generally accepted in the United States of America for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by generally accepted accounting principles for complete financial statements. In the opinion of management, all adjustments considered necessary for a fair presentation have been included and are of a normal and recurring nature. Operating results for the six month period ended June 30, 2009 are not necessarily indicative of the results that may be expected for future fiscal periods. Events occurring subsequent to June 30, 2009, have been evaluated as to their potential impact to the financial statements through the date of issuance, August 14, 2009. The financial statements should be read in conjunction with the audited consolidated financial statements and footnotes thereto included in the Company’s Annual Report on Form 10-K/T for the Transition Period ended December 31, 2008.

Certain reclassifications of prior year reported amounts have been made for comparative purposes. Contributions in Aid of Construction were reclassified to offset net fixed assets. Additionally, recoverable costs of gas were separated into assets and liabilities.

Energy, Inc. is the parent company of Energy West which is a natural gas utility with operations in Montana, Wyoming, North Carolina and Maine. The Company was originally incorporated in Montana in 1909. The Company currently has four reporting segments:

•	Natural Gas Operations	Annually, the Company distributes approximately 26 billion cubic feet of natural gas to approximately 37,000 customers through regulated utilities operating in and around Great Falls and West Yellowstone, Montana, Cody, Wyoming, Bangor, Maine and Elkin, North Carolina. The approximate population of the service territories is 177,000. The operation in Elkin, North Carolina was added October 1, 2007. The operation in Bangor, Maine was added December 1, 2007.
•	Marketing and Production Operations (EWR)	Annually, the Company markets approximately 2.3 billion cubic feet of natural gas to commercial and industrial customers in Montana and Wyoming and manages midstream supply and production assets for transportation customers and utilities through its subsidiary, Energy West Resources, Inc. (EWR). EWR owns an average 60% gross working interest (an average 51% net revenue interest) in 160 natural gas producing wells and gas gathering assets. Energy West Propane, Inc. dba Missouri River Propane (MRP), the Company’s small Montana wholesale distribution company that sells propane to its affiliated utility, is also reported in marketing and production operations.

6

•	Pipeline Operations (EWD)	The Company owns the Shoshone interstate and the Glacier gathering natural gas pipelines located in Montana and Wyoming through our subsidiary Energy West Development, Inc. (EWD). Certain natural gas producing wells owned by the Company’s pipeline operations are being managed and reported under our marketing and production operations.
•	Corporate and Other	The corporate and other segment was created to accumulate revenues and expenses that are not allocable to our utilities or other operations. Reported in corporate and other for the six months ended June 30, 2009 are costs associated with business development and acquisitions, and dividend income from marketable securities.

NOTE 1 — MARKETABLE SECURITIES

Securities investments not classified as either held-to-maturity or trading securities are classified as available-for-sale securities. Available-for-sale securities are recorded at fair value in marketable securities on the balance sheet, with the change in fair value during the period excluded from earnings and recorded net of tax as a component of other comprehensive income.

The following is a summary of available-for-sale securities at June 30, 2009:

	June 30, 2009
	Investment		Unrealized		Estimated
	at cost		gains		Fair Value
Common Stock	$	4,964,203	$	738,529	$	5,702,732

As of June 30, 2009 unrealized gain on available-for-sale securities of $454,491 (net of $284,038 in taxes) was included in accumulated other comprehensive income in the accompanying unaudited condensed consolidated balance sheets.

NOTE 2 — FAIR VALUE MEASUREMENTS

In September 2006, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards (SFAS) No. 157, “Fair Value Measurements,” (SFAS 157), which is effective for fiscal years beginning after November 15, 2007 and for interim periods within those years. This statement defines fair value, establishes a framework for measuring fair value and expands the related disclosure requirements. The statement indicates, among other things, that a fair value measurement assumes that the transaction to sell an asset or transfer a liability occurs in the principal market for the asset or liability or, in the absence of a principal market, the most advantageous market for the asset or liability based upon an exit price model.

Valuation Hierarchy

In accordance with SFAS 157, the following table represents the Company’s fair value hierarchy for its financial assets measured at fair value on a recurring basis as of June 30, 2009:

	June 30, 2009
	Level I		Level 2		Level 3		TOTAL
Available-for-sale securities	$	5,702,732		—		—	$	5,702,732
Total assets at fair value	$	5,702,732	$	—	$	—	$	5,702,732

7

NOTE 3 — DEFERRED CHARGES

Deferred Charges consist of the following:

	June 30,				December 31,
	2009		2008		2008
Regulatory asset for property taxes	$	1,401,120	$	1,707,370	$	1,554,244
Regulatory asset for income taxes		452,645		452,646		452,646
Regulatory asset for deferred environmental remediation costs		45,234		149,625		114,960
Rate case costs		18,538		11,525		18,538
Unamortized debt issue costs		394,718		440,490		417,768
Total	$	2,312,255	$	2,761,656	$	2,558,156

Regulatory assets will be recovered over a period of approximately seven to twenty years.

The property tax asset does not earn a return in the rate base; however the property tax is recovered in rates over a ten-year period starting January 1, 2004. The income taxes and environmental remediation costs earn a return equal to that of the Company’s rate base. No other assets earn a return or are recovered in the rate structure.

NOTE 4 — ACCRUED AND OTHER CURRENT LIABILITIES

Accrued and other current liabilities consist of the following:

	June 30,				December 31,
	2009		2008		2008
Property tax settlement—current portion	$	242,121	$	235,772	$	235,772
Payable to employee benefit plans		126,564		119,269		57,617
Accrued vacation		582,481		310,472		464,153
Customer deposits		472,607		498,880		501,248
Accrued interest		8,931		276		4,897
Accrued taxes other than income		652,738		474,775		492,320
Customer prepayments from levelized billing		1,093,477		554,765		2,075,860
Other		760,578		1,108,503		1,150,817
Total	$	3,939,497	$	3,302,712	$	4,982,684

8

NOTE 5 — OTHER LONG-TERM LIABILITIES

Other long-term liabilities consist of the following:

	June 30,				December 31
	2009		2008		2008
Asset retirement obligation	$	766,167	$	726,231	$	746,199
Customer advances for construction		769,596		734,862		824,955
Regulatory liability for income taxes		83,161		83,161		83,161
Long-term notes payable		31,410		—		—
Property tax settlement		729,008		972,008		729,008
Total	$	2,379,342	$	2,516,262	$	2,383,323

NOTE 6 — LINES OF CREDIT AND LONG-TERM DEBT

The Company funds its operating cash needs, as well as dividend payments and capital expenditures, primarily through cash flow from operating activities and short-term borrowing. Historically, to the extent cash flow has not been sufficient to fund these expenditures, the Company has used the working capital line of credit portion of the credit facility with Bank of America, N.A. (“Bank of America”) (fka LaSalle Bank, N.A.) The Company has greater need for short-term borrowing during periods when internally generated funds are not sufficient to cover all capital and operating requirements, including costs of gas purchased and capital expenditures. In general, the Company’s short-term borrowing needs for purchases of gas inventory and capital expenditures are greatest during the summer and fall months and our short-term borrowing needs for financing customer accounts receivable are greatest during the winter months.

Bank of America Line of Credit— On June 29, 2007, Energy West, Incorporated established its five-year unsecured credit facility with Bank of America, replacing a previous $20 million one-year facility with Bank of America which was scheduled to expire in November 2007. The credit facility includes an annual commitment fee equal to 0.20% of the unused portion of the facility and interest on amounts outstanding at the London Interbank Offered Rate, plus 120 to 145 basis points, for interest periods selected by the Company.

Long-term Debt—$13.0 million 6.16% Senior Unsecured Notes— On June 29, 2007, Energy West, Incorporated authorized the sale of $13.0 million aggregate principal amount of its 6.16% Senior Unsecured Notes, due June 29, 2017. The proceeds of these notes were used to refinance the Company’s existing notes. With this refinancing, the Company expensed the remaining debt issue costs of $991,000 in fiscal 2007, and incurred approximately $463,000 in new debt issue costs to be amortized over the life of the new notes.

Debt Covenants— The Company’s 6.16% Senior Unsecured Notes and the Bank of America credit facility agreements contain various covenants, which include, among others, limitations on total dividends and distributions made in the immediately preceding 60-month period to 75% of aggregate consolidated net income for such period, restrictions on certain indebtedness, limitations on asset sales, and maintenance of certain debt-to-capital and interest coverage ratios. At June 30, 2009, the Company believes it was in compliance with the financial covenants under its debt agreements.

At June 30, 2009, the Company had approximately $699,000 in cash ($277,000 net of bank overdrafts). In addition, at June 30, 2009, the Company had $3.6 million in borrowings under the Bank of America revolving line of credit. At June 30, 2009, the Company had outstanding letters of credit related to supply contracts totaling $1.2 million, which reduced available borrowings. The Company’s net availability at June 30, 2009, was $15.2 million under the Bank of America revolving line of credit.

The total amount outstanding under all of the Company’s long-term debt obligations was $13.0 million at June 30, 2009, and 2008. The portion of such obligations due within one year was $0 at June 30, 2009 and 2008.

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NOTE 7 — INCOME TAX EXPENSE

Income tax expense (benefit) differs from the amount computed by applying the federal statutory rate to pre-tax income or loss as demonstrated in the following table:

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2009			2008			2009			2008
Income tax from continuing operations:
Tax expense at statutory rate of 34%	$	403,289		$	22,984		$	1,488,886		$	1,103,728
State income tax expense, net of federal tax expense		27,087			1,544			100,001			114,697
Amortization of deferred investment tax credits		(5,266	)		(5,266	)		(10,531	)		(10,532	)
Other*		74,949			33,037			151,911			(149,033	)
Total income tax expense	$	500,059		$	52,299		$	1,730,267		$	1,058,860

* Other includes an adjustment for prior year actual tax expense from amounts that had been estimated and accrued.

In July 2006, the FASB issued FASB Interpretation No. 48,“Accounting for Uncertainty in Income Taxes — An Interpretation of FASB Statement No. 109”(“FIN 48”). FIN 48 prescribes detailed guidance for the financial statement recognition, measurement and disclosure of uncertain tax positions recognized in an enterprise’s financial statements in accordance with SFAS No. 109,“Accounting for Income Taxes.”Tax positions must meet a more-likely-than-not recognition threshold at the effective date to be recognized upon the adoption of FIN 48 and in subsequent periods. FIN 48 is effective for fiscal years beginning after December 15, 2006 and the provisions of FIN 48 are applied to all tax positions. Upon the adoption of FIN 48, the Company had no unrecognized tax benefits that would have a material impact to the Company’s financial statements for any open tax years. During the six months ended June 30, 2009, no adjustments were recognized for uncertain tax positions.

The Company recognizes interest accrued related to unrecognized tax benefits in interest expense and penalties in operating expense. No interest and penalties related to unrecognized tax benefits were accrued at June 30, 2009.

The tax years 2004 through 2007 remain open to examination by the major taxing jurisdictions in which the Company operates, although no material changes to unrecognized tax positions are expected within the next twelve months.

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NOTE 8 — SEGMENTS OF OPERATIONS

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2009			2008			2009			2008
Gross margin (operating revenue less cost of gas purchased):
Natural gas operations	$	4,514,827		$	4,397,709		$	11,221,545		$	10,855,731
EWR		621,925			113,881			1,576,618			1,205,222
Pipeline operations		111,401			93,519			224,067			183,316
	$	5,248,153		$	4,605,109		$	13,022,230		$	12,244,269
Operating income (loss):
Natural gas operations	$	1,007,763		$	590,652		$	3,776,569		$	3,149,564
EWR		442,485			(59,627	)		1,186,673			895,192
Pipeline operations		73,234			23,855			124,102			63,574
Corporate and other operations		—			(441,123	)		—			(441,123	)
	$	1,523,482		$	113,757		$	5,087,344		$	3,667,207
Net income (loss):
Natural gas operations	$	558,644		$	150,877		$	2,097,477		$	1,761,565
EWR		266,265			(49,389	)		689,180			621,736
Pipeline operations		43,218			11,649			72,726			33,454
Corporate and other operations		(182,042	)		(233,036	)		(210,575	)		(229,356	)
	$	686,085		$	(119,899	)	$	2,648,808		$	2,187,399

NOTE 9 — STOCK OPTIONS AND SHAREHOLDER RIGHTS PLANS

2002 Stock Option Plan— The Energy, Inc 2002 Stock Option Plan (the “Option Plan”) provides for the issuance of up to 300,000 options to purchase the Company’s common stock to be issued to certain key employees. As of June 30, 2009, there were 34,500 options outstanding, and the maximum number of shares available for future grants under this plan is 58,500 shares. Under the Option Plan, the option price may not be less than 100% of the common stock fair market value on the date of grant (in the event of incentive stock options, 110% of the fair market value if the employee owns more than 10% of the Company’s outstanding common stock). Pursuant to the Option Plan, the options vest over four to five years and are exercisable over a five to ten-year period from date of issuance.

SFAS No. 123 Disclosures— Effective July 1, 2005, the Company adopted the provisions of SFAS No. 123Accounting for Stock-Based Compensation. The fair value of each option grant is estimated on the date of grant using the Black-Scholes option pricing model.

In the quarters ended June 30, 2009 and 2008, 5,000 and 0 options were granted, respectively. At June 30, 2009 and 2008, a total of 34,500 and 19,500 options were outstanding, respectively.

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A summary of the status of the Company’s stock option plans as of June 30, 2009 and December 31, 2008 and changes during the periods ended on these dates is presented below.

			Weighted		Aggregate
	Number of		Average		Intrinsic
	Shares		Exercise Price		Value
Outstanding June 30, 2008		19,500	$	9.10
Granted		10,000	$	7.10
Exercised		—	$	—
Expired		—	$	—
Outstanding December 31, 2008		29,500	$	8.42
Granted		—	$	—
Exercised		—	$	—
Expired		—	$	—
Outstanding March 31, 2009		29,500	$	8.42
Granted		5,000	$	8.20
Exercised		—	$	—
Expired		—	$	—
Outstanding June 30, 2009		34,500	$	8.39	$	27,140
Exercisable June 30, 2009		18,750	$	9.44	$	4,250

The following information applies to options outstanding at June 30, 2009:

					Weighted
					Average
			Weighted		Remaining
			Average		Contractual
	Number		Exercise		Life		Number
Grant Date	Outstanding		Price		(Years)		Exercisable
1/6/2006		4,500	$	6.35		1.5		0
12/1/2007		15,000	$	9.93		1.0		15,000
12/1/2008		10,000	$	7.10		9.4		2,500
6/3/2009		5,000	$	8.20		4.9		1,250
		34,500						18,750

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NOTE 10 — COMPREHENSIVE INCOME

Comprehensive income includes net income and other comprehensive income, which is primarily comprised of unrealized holding gains or losses on our available-for-sale securities that are excluded from the statement of income in computing net income and reported separately in stockholders’ equity. Comprehensive income and its components are as follows:

	Three months ended					Six months ended
	June 30,					June 30,
	2009		2008			2009		2008
Net income (loss)	$	686,085	$	(119,899	)	$	2,648,808	$	2,187,399
Other comprehensive income:
Change in unrealized gain on available-for-sale securities, net of tax		454,491		—			454,491		—
Comprehensive income (loss)	$	1,140,576	$	(119,899	)	$	3,103,299	$	2,187,399

Other comprehensive income is $454,491, net of $284,038 in taxes as of June 30, 2009.

NOTE 11 — CONTINGENCIES

Derivative Contingencies— Among the risks involved in natural gas marketing is the risk of nonperformance by counterparties to contracts for purchase and sale of natural gas. The Company’s marketing operation is party to certain contracts for purchase or sale of natural gas at fixed prices for fixed time periods. The Company determined that these contracts qualify for treatment as a “normal purchase or normal sale” under SFAS 133.

Legal Proceedings— The Company is involved in lawsuits that have arisen in the ordinary course of business. The Company is contesting each of these lawsuits vigorously and believes it has defenses to the allegations that have been made.

On February 21, 2008, a lawsuit captionedShelby Gas Association v. Energy West Resources, Inc., Case No. DV-08-008, was filed in the Ninth Judicial District Court of Toole County, Montana. Shelby Gas Association (Shelby) alleges a breach of contract by the Company’s subsidiary, EWR, to provide natural gas to Shelby. Shelby is seeking damages and injunctive relief prohibiting EWR from further breaching the contract. The parties have filed cross motions for summary judgment which are pending. The court heard oral arguments for the pending motions on July 24, 2009, and the Company expects to receive the court’s ruling on the pending motions in the next month. The Company believes this lawsuit to be without merit and is vigorously defending the allegations.

In the Company’s opinion, the outcome of these lawsuits, including the Shelby litigation, will not have a material adverse effect on the Company’s financial condition, cash flows or results of operations.

NOTE 12 — NEW ACCOUNTING PRONOUNCEMENTS

Recently adopted

In September 2006, the FASB issued SFAS No. 157,Fair Value Measurements(“SFAS157”). SFAS 157 defines fair value, establishes a framework and gives guidance regarding the methods used for measuring fair value, and expands disclosures about fair value measurements. SFAS 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. On January 1, 2008 we elected to implement this statement with the one-year deferral. The adoption of SFAS No. 157 did not have a material impact on our financial position, results of operations or cash flows. Beginning January 1, 2009, we have adopted the provisions for non-financial assets and non-financial liabilities that are not required or permitted to be measured at fair value on a recurring basis.

In December 2007, the FASB issued SFAS No. 141 (revised 2007),Business Combinations(“SFAS 141R”). SFAS141R requires an acquirer to recognize and measure the assets acquired, liabilities assumed and any non-controlling interests in the acquiree at the acquisition date, measured at their fair values as of that date, with limited exception. In addition, SFAS141R requires that acquisition-related costs will be generally expensed as incurred and also expands the disclosure requirements for business combinations. The effective date of SFAS 141R is for years beginning after December 15, 2008. We have adopted SFAS 141R on our consolidated financial statements, effective January 1, 2009. In addition, we have recorded as expense in the six months ended June 30, 2009, $346,000 of acquisition costs related to acquisitions in progress as part of the transition to SFAS 141R.

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In December 2007, the FASB issued SFAS No. 160,Accounting for Noncontrolling Interests(“SFAS 160”). SFAS 160 amends Accounting Research Bulletin (ARB) No. 51 and establishes standards of accounting and reporting on non-controlling interests in consolidated statements, provides guidance on accounting for changes in the parent’s ownership interest in a subsidiary, and establishes standards of accounting of the deconsolidation of a subsidiary due to the loss of control. The effective date of SFAS 160 is for fiscal years beginning after December 15, 2008. We have adopted SFAS 160 on our consolidated financial statements, effective January 1, 2009, and the implementation did not have a material impact on our consolidated financial statements.

In March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities” (“SFAS 161”). SFAS 161 amends and expands the disclosure requirements of SFAS 133, “Accounting for Derivative Instruments and Hedging Activities” and requires qualitative disclosures about objectives and strategies for using derivatives, quantitative disclosures about fair value amounts of gains and losses on derivative instruments, and disclosures about credit-risk-related contingent features in derivative agreements. This statement is effective for financial statements issued for fiscal periods beginning after November 15, 2008. We implemented SFAS No. 161 on January 1, 2009, and the implementation did not have a material impact on our consolidated financial statements.

In May 2009, the FASB issued SFAS No. 165, “Subsequent Events”(“SFAS 165”), which provides guidance to establish general standards of accounting for and disclosures of events that occur after the balance sheet date but before financial statements are issued or are available to be issued. SFAS 165 does not result in significant changes in the subsequent events that an entity reports. Rather, SFAS 165 requires disclosure of the date through which subsequent events have been evaluated and whether that date represents the date the financial statements were issued or were available to be issued. SFAS 165 is effective for interim and annual periods ending after June 15, 2009. The disclosures required by this statement are included in Basis of Presentation section at the beginning of the Notes to Condensed Consolidated Financial Statements (unaudited).

Recently Issued

FSP 107-1,Interim Disclosures about Fair Value of Financial Instruments(FSP 107-1), increases the frequency of fair value disclosures required by SFAS No. 107,Disclosures About Fair Value of Financial Instruments(SFAS No. 107). FSP 107-1 relates to fair value disclosures for any financial instruments that are not currently reflected on the balance sheet of companies at fair value. Prior to issuing this FSP, fair values for these assets and liabilities were only required to be disclosed once a year. The FSP now requires these disclosures on a quarterly basis, providing qualitative and quantitative information about fair value estimates for all those financial instruments not measured on the balance sheet at fair value. Based on our evaluation of FSP 107-1, we expect to provide the disclosures required in SFAS No. 107 in interim periods beginning in July, 2009.

In April 2009, the FASB also issued FSP FAS 115-2 and FAS 124-2, “Recognition and Presentation of Other-Than-Temporary Impairments” (FSP FAS 115-2 and FAS 124-2)which changes the method for determining whether an other-than-temporary impairment exists for debt securities, and also requires additional disclosures regarding other-than-temporary impairments. FSP FAS 115-2 and FAS 124-2 is effective for interim and annual periods ending after June 15, 2009. We do not expect the implementation of FSP FAS 115-2 and FAS 124-2 to have a material impact on our consolidated financial statements.

In June 2009, the FASB issued SFAS No. 166,Accounting for Transfers of Financial Assets (“SFAS 166”),which changes the way entities account for securitizations. SFAS 166 is a revision to SFAS 140,Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities, and will require more information about transfers of financial assets, including securitization transactions, and any continuing exposure to the risks related to such transferred financial assets. It eliminates the concept of a qualifying special-purpose entity,” changes the requirements for derecognizing financial assets, and requires additional disclosures. SFAS 166 is effective for fiscal years beginning after November 15, 2009, for interim periods within that first annual reporting period and for interim and annual reporting periods thereafter. We are currently evaluating the impact, if any, of adopting SFAS 166 on our financial position and results of operations.

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ITEM 2 —  MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.

This quarterly report on Form 10-Q contains various “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended (the Exchange Act), which represent our expectations or beliefs concerning future events. Forward-looking statements generally include words such as “anticipates,” “believes,” “expects,” “planned,” “scheduled” or similar expressions and statements concerning our operating capital requirements, negotiations with our lender, recovery of property tax payments, our environmental remediation plans, and similar statements that are not historical are forward-looking statements that involve risks and uncertainties. Although we believe these forward-looking statements are based on reasonable assumptions, statements made regarding future results are subject to a number of assumptions, uncertainties and risks that could cause future results to be materially different from the results stated or implied in this document.

Such forward-looking statements, as well as other oral and written forward-looking statements made by or on behalf of us from time to time, including statements contained in filings with the SEC and our reports to shareholders, involve known and unknown risks and other factors that may cause our company’s actual results in future periods to differ materially from those expressed in any forward-looking statements. See “Risk Factors” in the our Annual Report on Form 10-K/T for the fiscal year ended December 31, 2008 filed with the SEC. Any such forward looking statement is qualified by reference to these risk factors. We caution that these risk factors are not exclusive. We do not undertake to update any forward looking statements that may be made from time to time by or on behalf of us except as required by law.

Overview

We are a natural gas utility with operations in Montana, Wyoming, North Carolina and Maine. We distribute 26 billion cubic feet (bcf) of natural gas annually to approximately 37,000 residential, commercial and industrial customers. In addition to our core natural gas distribution business, we market approximately 2.3 bcf of natural gas annually to commercial and industrial customers in Montana and Wyoming. We also have an average 60% gross working interest (average 51% net revenue interest) in 160 natural gas producing wells and gas gathering assets that provide our marketing and production operation with a partial hedge when gas prices are greater than the cost of production. In addition, we own the Shoshone interstate and the Glacier gathering pipelines located in Montana and Wyoming. We have four reporting segments. Our primary segments are natural gas operations, marketing and production operations and pipeline operations. Our other segment is corporate and other.

Pending Acquisitions

As previously disclosed, on June 26, 2009, we terminated the stock purchase agreement with Richard M. Osborne, Trustee, Rebecca Howell, Stephen G. Rigo, Marty Whelan and Thomas J. Smith (collectively, the Shareholders) whereby we agreed to purchase all of the common stock of Lightning Pipeline Co. (Lightning Pipeline), Great Plains Natural Gas Company (Great Plains), Brainard Gas Corp. (Brainard) and all of the membership units of Great Plains Land Development Co., Ltd. (GPL and collectively with Lightning Pipeline, Great Plains and Brainard, the Companies), which companies are primarily owned by an entity controlled by Mr. Osborne and wholly-owned by the Shareholders, for a purchase price of $34.3 million. Pursuant to the stock purchase agreement, we would have acquired Orwell Natural Gas Company (Orwell), a wholly-owned subsidiary of Lightening Pipeline and Northeast Ohio Natural Gas Corp. (NEO), a wholly-owned subsidiary of Great Plains. Orwell, NEO and Brainard are natural gas distribution companies that serve approximately 21,000 customers in Northeastern Ohio and Western Pennsylvania.

The parties determined that the proposed transaction might be better effectuated by mergers than stock purchases.

Accordingly, on June 29, 2009, we entered into an agreement and plan of merger (the merger agreement) with the Shareholders, Lightning Pipeline, Great Plains, Brainard and three to-be-formed wholly-owned Ohio subsidiary corporations of Energy, Inc. On June 29, 2009, we also entered into an agreement and plan of merger (together with the merger agreement, the merger agreements) with GPL, and an entity controlled by Mr. Osborne and a fourth to-be-formed acquisition subsidiary of Energy, Inc. (each acquisition subsidiary hereinafter referred to as an acquisition sub). The merger agreements provide for four separate mergers whereby an acquisition sub merges with and into each of the Companies. The Companies will survive the mergers, becoming four separate wholly- owned subsidiaries of Energy, Inc. The ultimate effect of the mergers is the same as the stock purchase transaction. The merger agreements are substantially the same as the stock purchase agreement in all material respects, including purchase price/consideration, assumption of debt, valuation and issuance of unregistered Energy, Inc. common stock, termination provisions and customary representations, warranties, covenants and indemnification provisions.

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Mr. Osborne is our chairman, chief executive officer and a director, Mr. Smith is our vice president, chief financial officer and a director, and Ms. Howell is our secretary.

The $34.3 million purchase price consists of our assumption of approximately $20.9 million in debt with the remainder of the purchase price to be paid in unregistered shares of common stock of Energy Inc. based on a price of $10.00 per share. The stock portion of the purchase price may be increased or decreased within three business days prior to closing of the transaction depending on the number of active customers of Orwell, Brainard and NEO. The Shareholders have the right to elect to terminate the transaction, upon the payment of a $100,000 fee, if the average closing price of our common stock for the twenty consecutive trading days ending seven calendar days prior to closing is below $9.49 and if our common stock underperforms the American Gas Stock Index (as maintained by the American Gas Association) by more than 20%, as described in the merger agreements. However, we may prevent termination of the transaction in this instance by increasing the number of shares of our common stock paid to the Shareholders as part of the purchase price. The merger agreements also contain customary representations, warranties, covenants and indemnification provisions.

The transaction is expected to close in the second half of 2009 but there can be no assurances that the transaction will be completed on the proposed terms or at all. The closing is subject to customary closing conditions, including the approval of applicable regulators. In addition, the transaction is subject to the approval of our shareholders for the issuance of shares of Energy, Inc. as part of the purchase price.

On December 18, 2007, we entered into a stock purchase agreement with certain shareholders of Cut Bank Gas Company, a natural gas utility serving Cut Bank, Montana, to acquire 83.16% of the outstanding shares of Cut Bank Gas for a purchase price of $500,000 paid in shares of common stock of Energy, Inc In addition, we will offer to purchase the remaining shares of Cut Bank Gas Company for a purchase price of $100,000 paid in shares of common stock of Energy Inc. The acquisition is subject to the approval of the MPSC and is expected to be completed in the second half of 2009. The acquisition is scheduled to close on the last business day of the month after all closing conditions have been satisfied, including MPSC approval, as the case may be. However, there can be no assurances the acquisition will be closed in this time frame, or at all.

New Holding Company Structure

On August 3, 2009, we completed a reorganization to implement a holding company structure. The new holding company, Energy, Inc., is the successor to Energy West, Incorporated, which is now a subsidiary of Energy, Inc. The purpose of the reorganization is to provide the flexibility to make future acquisitions through subsidiaries of the holding company rather than Energy West or its subsidiaries. The business operations of the company did not change as a result of the reorganization.

Outstanding shares of stock of Energy West were automatically converted on a share for share basis, into identical shares of common stock of the new holding company. The stock will continue to trade on the Nasdaq Global Market under the new trading symbol “EGAS.”

QUARTERLY RESULTS OF CONSOLIDATED OPERATIONS

The following discussion of our financial condition and results of operations should be read in conjunction with the Condensed Consolidated Financial Statements and Notes thereto and other financial information included elsewhere in this report and our Annual Report on Form 10-K/T for the transition period ended December 31, 2008.

Quarter Ended June 30, 2009 Compared to Quarter Ended June 30, 2008

The following gives effect to the unaudited Condensed Consolidated Financial Statements as of June 30, 2009 and for the three month period ended June 30, 2009. Results of operations for interim periods are not necessarily indicative of results to be attained for any future period.

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Net Income (Loss)— Our net income for the three months ended June 30, 2009 was approximately $686,000 compared to net loss of approximately $120,000 for the three months ended June 30, 2008, an increase of $806,000. This increase was primarily due to an increase in net income from our natural gas operations of $408,000, an increase in net income from our gas marketing and production operation of $316,000, an increase in income from our pipeline operations of $31,000 and a decrease in the net loss from our corporate and other segment of $51,000.

Revenues— Our revenues for the three months ended June 30, 2009 were approximately $12.2 million compared to approximately $17.6 million for the three months ended June 30, 2008, a decrease of $5.4 million. The decrease was primarily attributable to: (1) a natural gas revenue decrease of $4.6 million, due primarily to the significantly lower index price of natural gas passed through to our customers and (2) a decrease in our marketing and production operation’s revenue of $900,000, also caused primarily by significantly lower index prices for natural gas.

Gross Margin— Gross margin increased $600,000, to approximately $5.2 million in the three months ended June 30, 2009 from approximately $4.6 million in three months ended June 30, 2008. Our marketing and production operation’s margin increased by $500,000 due to a much more favorable cost of supply relative to our sales contracts, offset by lower margins from gas production, due to the lower prices for natural gas. Our natural gas operation’s margins increased $100,000, due to a favorable change in the mix of higher versus lower margin customers.

Expenses Other Than Cost of Sales— Expenses other than cost of sales decreased by $800,000 to $3.7 million in the three months ended June 30, 2009 as compared to $4.5 million in the three months ended June 30, 2008. The three months ended June 30, 2008 includes $441,000 of costs related to an equity offering that was not completed. The remaining $359,000 decrease is due primarily to lower distribution, general and administrative expenses, which were caused by much lower costs for fuel used in operations, and decreases in taxes other than income due to successful renegotiation for lower property taxes in our Maine operation. These decreases are partially offset by increases to depreciation expense.

Other Income— Other income (expense) decreased by $163,000 to a loss of $85,000 in the three months ended June 30, 2009 from income of $78,000 in the three months ended June 30, 2008. Dividend and other income from our corporate and other segment decreased by $24,000 and the three months ended June 30, 2009 includes $257,000 of acquisition related costs related to the merger agreements. Other income from our natural gas operations increased by $131,000 due primarily to a refund of prior year property insurance premiums.

Interest Expense— Interest expense decreased by approximately $7,000 to $252,000 during the three months ended June 30, 2009 from $259,000 in the three months ended June 30, 2008.

Income Tax Expense— Income tax expense increased by $448,000 to approximately $500,000 in the three months ended June 30, 2009 as compared to approximately $52,000 in the three months ended June 30, 2008, due to higher pre-tax income.

Six Months Ended June 30, 2009 Compared to Six Months Ended June 30, 2008

The following gives effect to the unaudited Condensed Consolidated Financial Statements as of June 30, 2009 and for the six month period ended June 30, 2009. Results of operations for interim periods are not necessarily indicative of results to be attained for any future period.

Net Income (Loss)— Our net income for the six months ended June 30, 2009 was approximately $2.6 million compared to a net income of approximately $2.2 million for the six months ended June 30, 2008, an increase of $400,000. This increase was primarily due to an increase in net income from our natural gas operations of $335,000 and an increase in net income from our gas marketing and production operation of $65,000.

Revenues— Our revenues for the six months ended June 30, 2009 were approximately $43.6 million compared to approximately $48.5 million for the six months ended June 30, 2008, a decrease of $4.9 million. The decrease was primarily attributable to: (1) a natural gas revenue decrease of $2.5 million, due primarily to significantly lower index prices for natural gas passed through to our customers, offset by sales growth in our Maine market in the first quarter of 2009 and (2) a decrease in our marketing and production operation’s revenue of $2.4 million, also caused primarily by significantly lower index prices for natural gas.

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Gross Margin— Gross margin increased $800,000, to approximately $13.0 million in the six months ended June 30, 2009 from approximately $12.2 million in six months ended June 30, 2008. Our natural gas operation’s margins increased $400,000, due primarily to sales growth in our Maine market in the first quarter of 2009 and a favorable change in the mix of higher versus lower margin customers. Our marketing and production operation’s margin increased by $400,000 due to a much more favorable cost of supply relative to our sales contracts, and offset by lower margins from gas production from the lower prices for natural gas.

Expenses Other Than Cost of Sales— Expenses other than cost of sales decreased by $643,000 to $7.9 million in the six months ended June 30, 2009 as compared to $8.6 million in the six months ended June 30, 2008. The six months ended June 30, 2008 includes $441,000 of costs related to an equity offering that was not completed. The remaining $202,000 variance is due primarily to decreases in distribution, general and administrative expenses, which were caused primarily by much lower costs for fuel used in operations, and decreases in taxes other than income due to successful negotiation for lower property taxes in our Maine operation. These decreases are partially offset by increases to depreciation expense.

Other Income— Other income (expense) decreased by $236,000 to a loss of $110,000 in the six months ended June 30, 2009 from income of $126,000 in the six months ended June 30, 2008. Other income from our natural gas operations increased by $106,000 due primarily to a refund of prior year property insurance premiums. Results from our corporate and other segment include $346,000 of acquisition related costs in the six months ended June 30, 2009, offset by an increase in dividend income of approximately $17,000. Marketing and production operations for 2009 includes a loss related to our equity investment in Kykuit of $13,000.

Interest Expense— Interest expense increased by $51,000 to approximately $598,000 during the six months ended June 30, 2009 from $547,000 in the six months ended June 30, 2008, due to an increase in short-term borrowings, caused primarily by the higher natural gas commodity prices during the summer and fall of 2008.

Income Tax Expense— Income tax expense increased by $600,000 to $1.7 million in the six months ended June 30, 2009 as compared to $1.1 million in the six months ended June 30, 2008, due primarily to higher pre-tax income. The six months ended June 30, 2008 included a negative adjustment to tax expense related to prior year tax and adjustments in the manner in which taxable income was apportioned to various states.

Operating Results of our Natural Gas Operations

	Three Months Ended June 30,						Six Months Ended June 30,
	2009			2008			2009			2008
Natural Gas Operations
Operating revenues	$	9,544,306		$	14,053,222		$	35,685,876		$	38,220,701
Gas purchased		5,029,479			9,655,513			24,464,331			27,364,970
Gross margin		4,514,827			4,397,709			11,221,545			10,855,731
Operating expenses		3,507,064			3,807,057			7,444,976			7,706,167
Operating income		1,007,763			590,652			3,776,569			3,149,564
Other income		142,488			11,531			161,821			55,497
Income before interest and taxes		1,150,251			602,183			3,938,390			3,205,061
Interest expense		(252,824	)		(232,637	)		(540,171	)		(471,675	)
Income before income taxes		897,427			369,546			3,398,219			2,733,386
Income tax expense		(338,783	)		(218,669	)		(1,300,742	)		(971,821	)
Net income	$	558,644		$	150,877		$	2,097,477		$	1,761,565

Quarter Ended June 30, 2009 Compared to Quarter Ended June 30, 2008

Natural Gas Revenues and Gross Margins— Our operating revenues in the three months ended June 30, 2009 decreased to approximately $9.5 million from approximately $14.1 million in the three months ended June 30, 2008. This $4.6 million decrease was primarily due to the significantly lower index price of natural gas passed through to our customers.

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Gas purchases in our natural gas operations decreased by $4.7 million to approximately $5.0 million in the three months ended June 30, 2009 from approximately $9.7 million in the three months ended June 30, 2008. This decrease reflects the significantly lower index price of natural gas.

Gross margin was approximately $4.5 million for the three months ended June 30, 2009, compared to approximately $4.4 million for the three months ended June 30, 2008. The increase of $100,000 is primarily due to a favorable change in the mix of higher versus lower margin customers.

Natural Gas Operating Expenses— Our operating expenses were approximately $3.5 million for the three months ended June 30, 2009, compared to approximately $3.8 million for the three months ended June 30, 2008. The $300,000 decrease is due primarily to decreases in general and administrative expenses, which were caused by much lower costs for fuel used in operations, and decreases in taxes other than income due to successful negotiation for lower property taxes in our Maine operations. These decreases are partially offset by increases in depreciation expense.

Natural Gas Other Income— Other income increased by $130,000 to $142,000 in the three months ended June 30, 2009 from $12,000 in the three months ended June 30, 2008. This was due primarily to increased service sales in Great Falls, Montana and a refund of prior year property insurance premiums.

Natural Gas Interest Expense— Interest expense increased by $20,000 to $253,000 in the three months ended June 30, 2009 from $233,000 in the three months ended June 30, 2008, due primarily to changes in our internal allocation of interest expense between operating segments.

Natural Gas Income Tax Expense— Income tax expense increased $120,000 to $339,000 in the three months ended June 30, 2009 compared to $219,000 in 2008 due to higher pretax income.

Six Months Ended June 30, 2009 Compared to Six Months Ended June 30, 2008

Natural Gas Revenues and Gross Margins— Our operating revenues in the six months ended June 30, 2009 decreased to approximately $35.7 million from approximately $38.2 million in the six months ended June 30, 2008. This $2.5 million decrease was due to the significantly lower index price of natural gas passed through to our customers, partially offset by sales growth in our Maine market in the first quarter of 2009.

Gas purchases in our natural gas operations decreased by $2.9 million to approximately $24.5 million in the six months ended June 30, 2009 from approximately $27.4 million in the six months ended June 30, 2008. This decrease reflects the significantly lower index price of natural gas and the offsetting increase in sales volumes in our Maine market in the first quarter of 2009.

Gross margin was approximately $11.2 million for the six months ended June 30, 2009, compared to approximately $10.9 million for the six months ended June 30, 2008. The increase of $300,000 is primarily due to sales growth in our Maine market in the first quarter of 2009 and a favorable change in the mix of higher versus lower margin customers.

Natural Gas Operating Expenses— Our operating expenses were approximately $7.4 million for the six months ended June 30, 2009, compared to approximately $7.7 million for the six months ended June 30, 2008. The $300,000 decrease is due to decreases in general and administrative expenses and taxes other than income taxes and offset by increases in depreciation expense.

Natural Gas Other Income— Other income increased by $107,000 to $162,000 in the six months ended June 30, 2009 from $55,000 in the six months ended June 30, 2008. This was due primarily to a refund of prior year property insurance premiums.

Natural Gas Interest Expense— Interest expense increased by $68,000 to $540,000 in the six months ended June 30, 2009 from $472,000 in the six months ended June 30, 2008, due to a change in our internal allocation of interest expense between operating segments and an increase in short-term borrowings, caused primarily by the higher natural gas commodity prices during the summer and fall of 2008.

Natural Gas Income Tax Expense— Income tax expense increased by $330,000 to approximately $1.3 million in the six months ended June 30, 2009 from approximately $970,000 in the six months ended June 30, 2008, due to higher pretax income. The six months ended June 30, 2008 included a negative adjustment to tax expense related to prior year tax and adjustments in the manner in which taxable income was apportioned to various states.

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Operating Results of our Marketing and Production Operations

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2009			2008			2009			2008
Energy West Resources
Operating revenues	$	2,582,758		$	3,494,963		$	7,662,345		$	10,115,959
Gas purchased		1,960,833			3,381,082			6,085,727			8,910,737
Gross margin		621,925			113,881			1,576,618			1,205,222
Operating expenses		179,440			173,508			389,945			310,030
Operating income (expense)		442,485			(59,627	)		1,186,673			895,192
Other income (expense)		(12,090	)		—			(12,090	)		511
Income (loss) before interest and taxes		430,395			(59,627	)		1,174,583			895,703
Interest income (expense)		3,436			(21,344	)		(51,907	)		(65,773	)
Income (loss) before income taxes		433,831			(80,971	)		1,122,676			829,930
Income tax (expense) benefit		(167,566	)		31,582			(433,496	)		(208,194	)
Net income (loss)	$	266,265		$	(49,389	)	$	689,180		$	621,736

Quarter Ended June 30, 2009 Compared to Quarter Ended June 30, 2008

Marketing and Production Revenues and Gross Margins— Our revenues decreased $900,000 to approximately $2.6 million in the three months ended June 30, 2009 from approximately $3.5 million in the three months ended June 30, 2008. Revenue from production decreased by $392,000 and retail gas revenues decreased by $460,000 with both decreases caused by significantly lower index prices for natural gas. Mark to market revenue decreased by $60,000.

The gross margin in our marketing and production operations increased $508,000 to approximately $622,000 in the three months ended June 30, 2009 from approximately $114,000 in the three months ended June 30, 2008. Gross margin from retail gas sales increased by $970,000 due to a much more favorable cost of supply relative to our sales contracts. Partially offsetting this is a decrease in gross margin from gas production of $402,000, due to the significantly lower index prices received for volumes produced, and the decrease in mark to market revenue.

Marketing and Production Operating Expenses— Our operating expenses increased approximately $5,000, to $179,000 in the three months ended June 30, 2009 from $174,000 in the three months ended June 30, 2008.

Marketing and Production Interest Expense— Interest expense decreased approximately $24,000 to an interest credit of $3,000 in the three months ended June 30, 2009 from expense of $21,000 in the three months ended June 30, 2008. This decrease is due primarily to changes made in our internal allocation of interest expense.

Marketing and Production Income Tax Benefit (Expense)— Income tax expense increased approximately $200,000 to $168,000 in the three months ended June 30, 2009 from a benefit of $32,000 in the three months ended June 30, 2008, due to the increase in pre-tax income.

Six Months Ended June 30, 2009 Compared to Six Months Ended June 30, 2008

Marketing and Production Revenues and Gross Margins— Our revenues decreased $2.4 million to approximately $7.7 million in the six months ended June 30, 2009 from approximately $10.1 million in the six months ended June 30, 2008. Revenue from production decreased by $350,000 and retail gas revenues decreased by $2.0 million with both decreases caused by significantly lower index prices for natural gas. Mark to market revenue decreased by $120,000.

The gross margin in our marketing and production operations increased $400,000 to approximately $1.6 million in the six months ended June 30, 2009 from approximately $1.2 million in the six months ended June 30, 2008. Gross margin from retail gas sales increased by $975,000 due to a much more favorable cost of supply, relative to our sales contracts. Partially offsetting this is a decrease in gross margin from gas production of $483,000, due to the significantly lower index prices received for volumes produced, and the decrease in mark to market revenue of $120,000.

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Marketing and Production Operating Expenses— Our operating expenses increased approximately $80,000, to $390,000 in the six months ended June 30, 2009 from $310,000 in the six months ended June 30, 2008. Increases in depletion, salary and benefits expense, employee travel, and professional services account for this change.

Marketing and Production Interest Expense— Interest expense decreased approximately $14,000 to $52,000 in the six months ended June 30, 2009 from $66,000 in the six months ended June 30, 2008. A credit due to a change in our intercompany interest allocation is partially offset by an increase in short-term borrowings, caused primarily by the higher natural gas commodity prices during the summer and fall of 2008.

Marketing and Production Income Tax Benefit (Expense)— Income tax expense increased approximately $225,000 to $433,000 in the six months ended June 30, 2009 from $208,000 in the six months ended June 30, 2008. The six months ended June 30, 2008 included a negative adjustment to tax expense related to prior year tax and adjustments in the manner in which taxable income was apportioned to various states. This combined with increased pre-tax income in the six months ended June 30, 2009, accounts for the change.

Operating Results of our Pipeline Operations

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2009			2008			2009			2008
Pipeline Operations
Operating revenues	$	111,401		$	93,519		$	224,067		$	183,316
Gas purchased		—			—			—			—
Gross margin		111,401			93,519			224,067			183,316
Operating expenses		38,167			69,664			99,965			119,742
Operating income		73,234			23,855			124,102			63,574
Other expense		—			(19	)		—			(19	)
Income before interest and taxes		73,234			23,836			124,102			63,555
Interest expense		(3,011	)		(4,905	)		(5,934	)		(9,186	)
Income before income taxes		70,223			18,931			118,168			54,369
Income tax expense		(27,005	)		(7,282	)		(45,442	)		(20,915	)
Net income	$	43,218		$	11,649		$	72,726		$	33,454

Quarter Ended June 30, 2009 Compared to the Quarter Ended June 30, 2008

Net income increased $31,000 to approximately $43,000 in the three months ended June 30, 2009 from approximately $12,000 in the three months ended June 30, 2008, and the overall impact of our pipeline operations was not material to our results of consolidated operations.

Six Months Ended June 30, 2009 Compared to the Six Months Ended June 30, 2008

Net income increased $40,000 to approximately $73,000 in the three months ended June 30, 2009 from approximately $33,000 in the three months ended June 30, 2008, and the overall impact of our pipeline operations was not material to our results of consolidated operations.

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Results of our Corporate and Other Operations

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2009			2008			2009			2008
Corporate and Other
Operating revenues	$	—		$	—		$	—		$	—
Gas purchased					—						—
Gross margin		—			—			—			—
Operating expenses		—			441,123			—			441,123
Operating loss		—			(441,123	)		—			(441,123	)
Other income (expense)		(215,337	)		66,017			(259,649	)		69,697
Loss before interest and taxes		(215,337	)		(375,106	)		(259,649	)		(371,426	)
Interest expense		—			—			(339	)		—
Loss before income taxes		(215,337	)		(375,106	)		(259,988	)		(371,426	)
Income tax benefit		33,295			142,070			49,413			142,070
Net loss	$	(182,042	)	$	(233,036	)	$	(210,575	)	$	(229,356	)

The corporate and other operations segment was created to accumulate revenues and expenses that are not allocable to our utilities or other operations. Therefore, it does not have standard revenues, gas purchase costs, or gross margin.

Quarter Ended June 30, 2009 Compared to the Quarter Ended June 30, 2008

Results of corporate and other operations for the three months ended June 30, 2009 include costs related to acquisition activities of $257,000, offset by dividends from marketable securities of approximately $42,000 and the applicable income tax benefit of approximately $33,000, for a net loss of approximately $182,000.

Results of corporate and other operations for the three months ended June 30, 2008 included approximately $61,000 in gains from the sale of marketable securities, approximately $5,000 in dividends from marketable securities, approximately $441,000 in costs associated with an equity offering that did not occur and the applicable income tax benefit of approximately $142,000 for a net loss of approximately $233,000.

Six Months Ended June 30, 2009 Compared to the Six Months Ended June 30, 2008

Results of corporate and other operations for the six months ended June 30, 2009 include costs related to acquisition activities of $346,000, offset by dividends from marketable securities of approximately $86,000 and the applicable income tax benefit of approximately $49,000, for a net loss of approximately $211,000.

Results of corporate and other operations for the six months ended June 30, 2008 included approximately $61,000 in gains from the sale of marketable securities, approximately $9,000 in dividends from marketable securities, approximately $441,000 in costs associated with an equity offering that was not completed and the applicable income tax benefit of approximately $142,000 for a net loss of approximately $229,000.

Consolidated Cash Flow Analysis

Sources and Uses of Cash

Operating activities provide our primary source of cash. Cash provided by operating activities consists of net income (loss) adjusted for non-cash items, including depreciation, depletion, amortization, deferred income taxes and changes in working capital.

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Our ability to maintain liquidity depends upon our $20.0 million credit facility with Bank of America, shown as line of credit on the accompanying balance sheets. Our use of the Bank of America revolving line of credit increased to $3.6 million at June 30, 2009, compared with $0 at June 30, 2008. This change in our line of credit is caused primarily by increased construction expenditures and purchases of marketable securities.

Long-term debt was $13.0 million at June 30, 2009, and 2008.

Cash decreased by $367,000 from December 31, 2008 to June 30, 2009, compared with the $1,109,000 decrease in cash for the six months ended June 30, 2008, as shown in the following table:

	June 30,
	2009			2008
Cash provided by operating activities	$	19,849,732		$	9,547,820
Cash used in investing activities		(5,211,859	)		(3,277,973	)
Cash used in financing activities		(15,004,893	)		(7,378,806	)
Decrease in cash	$	(367,020	)	$	(1,108,959	)

Cash provided by operating activities was approximately $10.3 million higher in the six months ended June 30, 2009, than the six months ended June 30, 2008. This was primarily due to increases in natural gas purchases of $4.8 million, recoverable gas purchases of $2.9 million, other assets (net of other liabilities) of $1.6 million, accounts receivable and prepaids of $3.7 million, deferred income taxes of $500,000 and net income of $500,000, and decreases in accounts payable of $3.7 million as compared to the six months ended June 30, 2008.

Cash used in investing activities was approximately $1.9 million higher in the six months ended June 30, 2009, than the six months ended June 30, 2008. This was due to an increase of $1.4 million for construction expenditures, an increase of $129,000 for investments, a decrease in customer advances received for construction and contributions in aid of construction of $141,000 and an increase of $226,000 in net purchases of marketable securities as compared to the six months ended June 30, 2008.

Cash used in financing activities in the six months ended June 30, 2009 was $15.0 million. This is $7.6 million more than the cash used of $7.4 million in the six months ended June 30, 2008 and is due to an increase in debt repayments of $9.1 million, increased borrowings of $1.7 million, decreased net sales of common stock of $102,000, and a $155,000 increase in dividends paid as compared to the six months ended June 30, 2008.

Liquidity and Capital Resources

We fund our operating cash needs, as well as dividend payments and capital expenditures, primarily through cash flow from operating activities and short-term borrowing. Historically, to the extent cash flow has not been sufficient to fund these expenditures; we have used our working capital line of credit. We have greater need for short-term borrowing during periods when internally generated funds are not sufficient to cover all capital and operating requirements, including costs of gas purchased and capital expenditures. In general, our short-term borrowing needs for purchases of gas inventory and capital expenditures are greatest during the summer and fall months and our short-term borrowing needs for financing customer accounts receivable are greatest during the winter months.

Long-term Debt — $13.0 million 6.16% Senior Unsecured Notes— On June 29, 2007, we issued $13.0 million aggregate principal amount of our 6.16% Senior Unsecured Notes, due June 29, 2017. The proceeds of these notes were used to refinance our existing notes. With this refinancing, we expensed the remaining debt issue costs of $991,000 in fiscal 2007, and incurred approximately $463,000 in new debt issue costs to be amortized over the life of the new note.

Bank of America Line of Credit— On June 29, 2007, we established our five-year unsecured credit facility with Bank of America, replacing a previous $20.0 million one-year facility with Bank of America which was scheduled to expire in November 2007. The credit facility includes an annual commitment fee equal to 0.20% of the unused portion of the facility and interest on amounts outstanding at the London Interbank Offered Rate, plus 120 to 145 basis points, for interest periods selected by us.

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The following table represents borrowings under the Bank of America revolving line of credit for each of the periods presented.

Quarter Ended June 30, 2009
Minimum borrowing	$	—
Maximum borrowing	$	5,045,000
Average borrowing	$	2,002,000

Quarter Ended March 31, 2009
Minimum borrowing	$	5,595,000
Maximum borrowing	$	18,095,000
Average borrowing	$	11,987,000

Our 6.16% Senior Unsecured Notes and Bank of America credit facility agreements contain various covenants, which include, among others, limitations on total dividends and distributions made in the immediately preceding 60-month period to 75% of aggregate consolidated net income for such period, restrictions on certain indebtedness, limitations on asset sales, and maintenance of certain debt-to-capital and interest coverage ratios. At June 30, 2009 and 2008, we believe we were in compliance with the financial covenants under our debt agreements.

At June 30, 2009, we had approximately $699,000 of cash on hand, ($277,000 net of bank overdrafts) and $3.6 million in borrowings under the $20.0 million Bank of America revolving line of credit. In addition, at June 30, 2009, we had two outstanding letters of credit related to supply contracts totaling $1.2 million. These letters of credit reduce our available borrowings on our line of credit. As discussed above, our short-term borrowing needs for purchases of gas inventory and capital expenditures are greatest during the summer and fall months. Our availability normally increases in January as monthly heating bills are paid and storage related gas purchases are no longer necessary.

The total amount outstanding under all of our long term debt obligations was $13.0 million at both June 30, 2009, and 2008. The portion of such obligations due within one year was $0 at both June 30, 2009, and 2008.

Capital Expenditures

We conduct ongoing construction activities in all of our utility service areas in order to support expansion, maintenance, and enhancement of our gas pipeline systems. We are actively expanding our systems in North Carolina and Maine to meet the high customer interest in natural gas service in those two service areas. For the six months ended December 31, 2008 our total capital expenditures were approximately $4.7 million. During the six months ended June 30, 2009 and 2008 capital expenditures were $3.9 million and $2.5 million, respectively. We estimate future cash requirements for capital expenditures will be as follows:

	Estimated
	Future Cash
	Requirements
	through 12/31/09
	(In thousands)
Natural Gas Operations	$	1,175
Energy West Resources		—
Pipeline Operations		—
Total capital expenditures	$	1,175

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Contractual Obligations

Our major financial market risk exposure is to changing interest rates. Changing interest rates will affect interest paid on variable-rate debt. Our policy is to manage interest rates through the use of a combination of fixed-rate and floating-rate debt.

The table below presents contractual balances of our consolidated long-term and short-term debt at the expected maturity dates as of June 30, 2009.

Payments Due by Period

			1 year						After
Contractual Obligations	Total		or less		2-3 years		4-5 years		5 years
Interest payments (a)	$	6,406,400	$	800,800	$	1,601,600	$	1,601,600	$	2,402,400
Long Term Debt (b)		13,000,000		—		—		—		13,000,000
Operating Lease Obligations		129,900		34,835		27,180		6,563		61,322
Transportation and Storage Obligation (c)		7,541,453		3,695,046		1,001,748		1,001,748		1,842,911
Total Obligations	$	27,077,753	$	4,530,681	$	2,630,528	$	2,609,911	$	17,306,633

(a)	Our long-term debt and notes payable require interest payments. Interest payments are projected based on debt service schedules provided at debt issuance.
(b)	See Note 6 of the Notes to the unaudited condensed consolidated financial statements for a description of this debt.
(c)	Transportation and Storage Obligations represent annual commitments with suppliers for periods extending up to seven years. These costs are recoverable in customer rates.

OFF-BALANCE SHEET ARRANGEMENTS

We do not have any off-balance-sheet arrangements, other than those currently disclosed that have or are reasonably likely to have a current or future effect on financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources that is material to investors.

ITEM 3 —  QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

We are subject to certain market risks, including commodity price risk (i.e., natural gas and propane prices) and interest rate risk. The adverse effects of potential changes in these market risks are discussed below. The sensitivity analyses presented do not consider the effects that such adverse changes may have on overall economic activity nor do they consider additional actions management may take to mitigate our exposure to such changes. Actual results may differ. See the notes to the financial statements for a description of our accounting policies and other information related to these financial instruments.

Commodity Price Risk

We seek to protect ourselves against natural gas price fluctuations by limiting the aggregate level of net open positions that are exposed to market price changes. We manage open positions with policies designed to limit the exposure to market risk, with regular reporting to management of potential financial exposure. Our Risk Management Committee has limited the types of contracts we will consider to those related to physical natural gas deliveries. Therefore, management believes that our results of operations are not significantly exposed to changes in natural gas prices.

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Interest Rate Risk

Our results of operations are affected by fluctuations in interest rates (e.g. interest expense on debt). We mitigate this risk by entering into long-term debt agreements with fixed interest rates. Some of our notes payable, however, may be subject to variable interest rates that we may mitigate by entering into interest rate swaps. A hypothetical 100 basis point change in market rates applied to the balance of the notes payable would change our interest expense by approximately $36,000 annually.

Credit Risk

Credit risk relates to the risk of loss that we would incur as a result of non-performance by counterparties of their contractual obligations under various instruments with us. Credit risk may be concentrated to the extent that one or more groups of counterparties have similar economic, industry or other characteristics that would cause their ability to meet contractual obligations to be similarly affected by changes in market or other conditions. In addition, credit risk includes not only the risk that a counterparty may default due to circumstances relating directly to it, but also the risk that a counterparty may default due to circumstances which relate to other market participants that have a direct or indirect relationship with such counterparty. We seek to mitigate credit risk by evaluating the financial strength of potential counterparties. However, despite mitigation efforts, defaults by counterparties may occur from time to time. To date, no such default has occurred.

Equity Price Risk

Equity securities are subject to equity price risk, which is defined as the potential for loss in market value due to a decline in equity prices. The value of common stock equity investments is dependent upon the general conditions in the securities markets and the business and financial performance of the individual companies in the portfolio. Values are typically based on future economic prospects as perceived by investors in the equity markets. We regularly review the carrying value of our investments and identify and record losses when events and circumstances indicate that such declines in the fair value of such assets below our accounting basis are other-than-temporary. For additional discussion of our equity securities, see Note 1 to the unaudited financial statements included herein.

ITEM 4(T) —  CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

As of June 30, 2009, we evaluated the effectiveness of the design and operation of our disclosure controls and procedures as defined in Rule 13a-15(e) of the Securities Exchange Act of 1934, as amended. The evaluation was carried out under the supervision of and with the participation of our management, including our principal executive officer and principal financial officer. Based upon this evaluation, our chief executive officer and chief financial officer each concluded that our disclosure controls and procedures were effective as of June 30, 2009.

Changes in Internal Control over Financial Reporting

There were no changes in our internal control over financial reporting during our last fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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PART II — OTHER INFORMATION

ITEM 6 —  EXHIBITS

Exhibit
Number	Description
31.1*	Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*	Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1*	Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2*	Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

* Filed or furnished herewith.

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SIGNATURES

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

	ENERGY, INC.
	/s/Thomas J. Smith
August 14, 2009	Vice President and Chief Financial Officer
	(principal financial officer and principal accounting officer)

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EXHIBIT INDEX

Exhibit
Number	Description
31.1*	Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*	Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1*	Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2*	Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

* Filed or furnished herewith.

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